0001130310cnp:SecuritizationBondsMembersrt:MinimumMembercnp:SIGECOSecuritizationBondsMembercnp:SIGECOMember2023-12-31



UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
______________________
Form 10-K
(Mark One)
☑
(Mark One)
þANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 20172023
OR
o☐TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM  TO 

Commission File Number 1-31447
______________________
CenterPoint Energy, Inc.
(Exact name of registrant as specified in its charter)
Texas74-0694415
(Registrant, State or other jurisdictionOther Jurisdiction
 of incorporationIncorporation or organization)Organization		(
Commission file numberAddress of Principal Executive Offices, Zip Code
 and Telephone Number		I.R.S. Employer Identification No.)
1-31447
CenterPoint Energy, Inc.74-0694415
(a Texas corporation)
1111 Louisiana
Houston,Texas77002
(713)207-1111
1-3187CenterPoint Energy Houston Electric, LLC22-3865106
(a Texas 77002
(Address and zip code of principal executive offices)
limited liability company)
1111 Louisiana
Houston,Texas77002
(713)207-1111
(Registrant’s telephone number, including area code)
1-13265CenterPoint Energy Resources Corp.76-0511406
(a Delaware corporation)
1111 Louisiana
Houston,Texas77002
(713)207-1111
Securities registered pursuant to Section 12(b) of the Act:
Securities registered pursuant to Section 12(b) of the Act:
Registrant
Title of each classTrading symbol(s)Name of each exchange on which registered
CenterPoint Energy, Inc.Common Stock, $0.01 par value
CNP
New York Stock Exchange
NYSE Chicago
CenterPoint Energy Houston Electric, LLC6.95% General Mortgage Bonds due 2033n/aNew York Stock Exchange
CenterPoint Energy Resources Corp.6.625% Senior Notes due 2037n/aNew York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
None
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes þ No o

CenterPoint Energy, Inc.Yesþ
No o
CenterPoint Energy Houston Electric, LLCYesþ
No o
CenterPoint Energy Resources Corp.Yesþ
No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  Yes o No þ

CenterPoint Energy, Inc.
Yes o
Noþ
CenterPoint Energy Houston Electric, LLC
Yes o
Noþ
CenterPoint Energy Resources Corp.
Yes o
Noþ



Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes þ No o

CenterPoint Energy, Inc.Yesþ
No o
CenterPoint Energy Houston Electric, LLCYesþ
No o
CenterPoint Energy Resources Corp.Yesþ
No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o

CenterPoint Energy, Inc.Yesþ
No o
CenterPoint Energy Houston Electric, LLCYesþ
No o
CenterPoint Energy Resources Corp.Yesþ
No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ


Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer”, “accelerated filer”, “smaller reporting company”, and “smaller reporting“emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filerþ
Accelerated filero
Non-accelerated filero
Smaller reporting companyo
Emerging growth companyo
CenterPoint Energy, Inc.þ(Do not check if a smaller reporting company)oo☐☐
CenterPoint Energy Houston Electric, LLCooþ☐☐
CenterPoint Energy Resources Corp.ooþ☐☐


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


Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☑

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements.

CenterPoint Energy, Inc.o
CenterPoint Energy Houston Electric, LLCo
CenterPoint Energy Resources Corp.o

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b).

CenterPoint Energy, Inc.o
CenterPoint Energy Houston Electric, LLCo
CenterPoint Energy Resources Corp.o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes o No þ

CenterPoint Energy, Inc.Yes☐
No þ
CenterPoint Energy Houston Electric, LLCYes☐
No þ
CenterPoint Energy Resources Corp.Yes☐
No þ

The aggregate market valuevalues of the voting stock held by non-affiliates of CenterPoint Energy, Inc. (CenterPoint Energy) was $11,722,467,012the Registrants as of June 30, 2017, using the definition of beneficial ownership contained in Rule 13d-3 promulgated pursuant to the Securities Exchange Act of 1934 and excluding shares held by directors and executive officers. As of February 9, 2018, CenterPoint Energy had 431,048,125 shares of Common Stock outstanding. Excluded from2023 are as follows:
CenterPoint Energy, Inc. (using the definition of beneficial ownership contained in Rule 13d-3 promulgated pursuant to Securities Exchange Act of 1934 and excluding shares held by directors and executive officers)$18,251,183,835
CenterPoint Energy Houston Electric, LLCNone
CenterPoint Energy Resources Corp.None

Indicate the number of shares outstanding of Common Stock outstanding areeach of the issuers’ classes of common stock as of  February 12, 2024:
CenterPoint Energy, Inc.631,594,706 shares of common stock outstanding, excluding 166 shares held as treasury stock
CenterPoint Energy Houston Electric, LLC1,000 common shares outstanding, all held by Utility Holding, LLC, a wholly-owned subsidiary of CenterPoint Energy, Inc.
CenterPoint Energy Resources Corp.1,000 shares of common stock outstanding, all held by Utility Holding, LLC, a wholly-owned subsidiary of CenterPoint Energy, Inc.

CenterPoint Energy as treasury stock.Houston Electric, LLC and CenterPoint Energy Resources Corp. meet the conditions set forth in general instruction I(1)(a) and (b) of Form 10-K and are therefore filing this Form 10-K with the reduced disclosure format specified in General Instruction I(2) of Form 10-K.


DOCUMENTS INCORPORATED BY REFERENCE


Portions of the definitive proxy statement relating to the 20182024 Annual Meeting of Shareholders of CenterPoint Energy, which will be filed with the Securities and Exchange Commission within 120 days of December 31, 2017,2023, are incorporated by reference in Item 10, Item 11, Item 12, Item 13 and Item 14 of Part III of this Form 10-K.





TABLE OF CONTENTS
PART I
Page
PART I
Page
Item 1.BusinessBusiness
1
Item 1A.Risk Factors
1718
Item 1B.Unresolved Staff Comments
4238
Item 2.1C.CybersecurityProperties
4238
Item 3.2.PropertiesLegal Proceedings
4240
Item 3.Legal Proceedings
43
Item 4.Mine Safety Disclosures
4243
PART II
Item 5.Market for Registrants’ Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
43
Item 6.[Reserved]Selected Financial Data
44
Item 7.Management’s Discussion and Analysis of Financial Condition and Results of Operations
4544
Item 7A.Quantitative and Qualitative Disclosures About Market Risk
7082
Item 8.Financial Statements and Supplementary Data
7284
Item 9.Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
125172
Item 9A.Controls and Procedures
125172
Item 9B.Other Information
128175
PART IIIItem 9C.Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
175
PART III
Item 10.Directors, Executive Officers and Corporate Governance
128176
Item 11.Executive Compensation
128176
Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
129177
Item 13.Certain Relationships and Related Transactions, and Director Independence
129177
Item 14.Principal Accounting Fees and Services
129177
PART IV
Item 15.Exhibits and Financial Statement Schedules
129178
Item 16.Form 10-K Summary
129178
 

i



GLOSSARY
ACEAffordable Clean Energy
GLOSSARY
ADFITAccumulated deferred federal income taxes
ADMSAdvanced Distribution Management System
AEMAtmos Energy Marketing, LLC, previously a wholly-owned subsidiary of Atmos Energy Holdings, Inc., a wholly-owned subsidiary of Atmos Energy Corporation
AFUDCAllowance for funds used during construction
AMAsAGCAlcoa Generating Corporation, a subsidiary of Alcoa, Inc.
AIArtificial intelligence
AMAsAsset Management Agreements
AMSAdvanced Metering System
AOL
ArevonAOLArevon Energy, Inc., which was formed through the combination of Capital Dynamics, Inc.’s U.S. Clean Energy Infrastructure business unit and Arevon Asset Management
APSCAROArkansas Public Service Commission
ArcLightArcLight Capital Partners, LLC
AROAsset retirement obligation
ASCAROK Asset Purchase AgreementAsset Purchase Agreement, dated as of April 29, 2021, by and between CERC Corp. and Southern Col Midco, LLC, a Delaware limited liability company and an affiliate of Summit Utilities, Inc.
ARPAlternative revenue program
ASCAccounting Standards Codification
ASUAccounting Standards Update
AT&TAT&T Inc.
AT&T CommonAT&T common stock
Bcf
ATM Forward PurchasersBank of America, N.A., Barclays Bank PLC, Citibank, N.A., Goldman Sachs & Co. LLC, JPMorgan Chase Bank, National Association, Mizuho Markets Americas LLC, MUFG Securities EMEA plc and Royal Bank of Canada
ATM Forward SellersBofA Securities, Inc. Barclays Capital Inc., Citigroup Global Markets Inc., Goldman Sachs & Co. LLC, J.P. Morgan Securities LLC, Mizuho Securities USA LLC, MUFG Securities Americas Inc. and RBC Capital Markets, LLC
ATM ManagersBofA Securities, Inc., Barclays Capital Inc., Citigroup Global Markets Inc., Goldman Sachs & Co. LLC, J.P. Morgan Securities LLC, Mizuho Securities USA LLC, MUFG Securities Americas Inc. and RBC Capital Markets, LLC
BcfBillion cubic feet
Btu
BoardBritish thermal unitsCenterPoint Energy’s Board of Directors
BDABilling Determinant Adjustment, which is a revenue stabilization mechanism used to adjust revenues impacted by declines in natural gas consumption which occurred after the most recent rate case
Bond CompaniesWholly-owned,Bond Company IV and Restoration Bond Company, each a wholly-owned, bankruptcy remote entitiesentity formed solely for the purpose of purchasing and owning transition or system restoration property through the issuance of Securitization Bonds
Brazos Valley Connection
Bond Company IVA portionCenterPoint Energy Transition Bond Company IV, LLC, a wholly-owned subsidiary of the Houston region transmission project between Houston Electric’s Zenith substation and the Gibbons Creek substation owned by the Texas Municipal Power AgencyElectric
CEA
BTACommodities Exchange Act of 1936Build Transfer Agreement
CEIPCAMTCorporate Alternative Minimum Tax
CARES ActCoronavirus Aid, Relief, and Economic Security Act
CCNCertificate of Convenience and Necessity
CCRCoal Combustion Residuals
CECAClean Energy Cost Adjustment
CEIPCenterPoint Energy Intrastate Pipelines, LLC, a wholly-owned subsidiary of CERC Corp.
CenterPoint EnergyCenterPoint Energy, Inc., and its subsidiaries
CERC Corp.CenterPoint Energy Resources Corp.
CERCCERC Corp., together with its subsidiaries
CERCLAComprehensive Environmental Response, Compensation and Liability Act of 1980, as amended
CESCenterPoint Energy Services, Inc. (now known as Symmetry Energy Solutions, LLC), previously a wholly-owned subsidiary of CERC Corp. until its divestiture on June 1, 2020
CFTCCommodity Futures Trading Commission
Charter CommonCharter Communications, Inc. common stock
Charter mergerMerger of Charter Communications, Inc. and Time Warner Cable Inc.
CIPConservation Improvement Program
COLI
CNGCorporate-owned life insuranceCompressed natural gas
Continuum
CodeThe retail energy services businessInternal Revenue Code of Continuum Retail Energy Services, LLC, including its wholly-owned subsidiary Lakeshore Energy Services, LLC and the natural gas wholesale assets of Continuum Energy Services, LLC1986, as amended
DCRFCODMChief Operating Decision Maker
Common StockCenterPoint Energy, Inc. common stock, par value $0.01 per share
Compensation CommitteeCompensation Committee of the Board
ii

GLOSSARY
Convertible NotesCenterPoint Energy’s 4.25% Convertible Senior Notes due 2026
COVID-19Novel coronavirus disease 2019, and any mutations or variants thereof, and related global outbreak that was subsequently declared a pandemic by the World Health Organization
CPCNCertificate of public convenience and necessity
CPPClean Power Plan
CSIACompliance and System Improvement Adjustment
DCRFDistribution Cost Recovery Factor
Dodd-Frank ActDE&I CouncilDodd-Frank Wall Street ReformDiversity, Equity and Consumer Protection Act of 2010Inclusion Council
DOEDOCU.S. Department of EnergyCommerce
DOTU.S. Department of Transportation
DthDRRDekathermsDistribution Replacement Rider
EBITDADSMAEarnings before interest, taxes, depreciation and amortizationDemand Side Management Adjustment
EDITDthDekatherms
ECAEnvironmental Cost Adjustment
EDF RenewablesEDF Renewables Development, Inc.
EDITExcess deferred income taxes

ii


EECR
GLOSSARY (cont.)
EECREnergy Efficiency Cost Recovery
EECRFEnergy Efficiency Cost Recovery Factor
EGTEEFCEnable Gas Transmission, LLCEnergy Efficiency Funding Component
EIAEEFREnergy Efficiency Funding Rider
ELGEffluent Limitation Guidelines
EIAU.S. Energy Information Administration
EnableElk GP Merger SubElk GP Merger Sub LLC, a Delaware limited liability company and a direct wholly-owned subsidiary of Energy Transfer
Elk Merger SubElk Merger Sub LLC, a Delaware limited liability company and a direct wholly-owned subsidiary of Energy Transfer
EnableEnable Midstream Partners, LP
EPAEnable Common UnitsEnvironmental Protection AgencyEnable common units, representing limited partnership interests in Enable
EPActEnable GPEnable GP, LLC, a Delaware limited liability company and the general partner of 2005Energy Policy Act of 2005Enable
ERCOTEnable MergerElectric Reliability CouncilThe merger of TexasElk Merger Sub with and into Enable and the merger of Elk GP Merger Sub with and into Enable GP, in each case on the terms and subject to the conditions set forth in the Enable Merger Agreement, with Enable and Enable GP surviving as wholly-owned subsidiaries of Energy Transfer, which closed on December 2, 2021
ERCOT ISOEnable Merger AgreementERCOT Independent System OperatorAgreement and Plan of Merger by and among Energy Transfer, Elk Merger Sub, Elk GP Merger Sub, Enable, Enable GP and, solely for the purposes of Section 2.1(a)(i) therein, Energy Transfer GP, and solely for the purposes of Section 1.1(b)(i) therein, CenterPoint Energy
ERISAEmployee Retirement Income Security Act of 1974
EROElectric Reliability Organization
FASBFinancial Accounting Standards Board
FERCFederal Energy Regulatory Commission
FitchFitch, Inc.
FRPFormula Rate Plan
Gas DailyPlatts gas daily indices
GenOnGenOn Energy, Inc.
GHGGreenhouse gases
GRIPGas Reliability Infrastructure Program
GWhGigawatt-hours
Houston ElectricCenterPoint Energy Houston Electric, LLC and its subsidiaries
HVACHeating, ventilation and air conditioning
IBEWInternational Brotherhood of Electrical Workers
ICAInterstate Commerce Act of 1887
IGIntelligent Grid
IRSInternal Revenue Service
kVKilovolt
LIBORLondon Interbank Offered Rate
LNGLiquefied natural gas
LPSCLouisiana Public Service Commission
LTIPsLong-term incentive plans
MeredithMeredith Corporation
MGPsManufactured gas plants
MLPMaster Limited Partnership
MMBtuOne million British thermal units
MMcfMillion cubic feet
Moody’sMoody’s Investors Service, Inc.
MPSCMississippi Public Service Commission
MPUCMinnesota Public Utilities Commission
MRTEnable-Mississippi River Transmission, LLC
NAVNet asset value
NECANational Electrical Contractors Association
NERCNorth American Electric Reliability Corporation
NESHAPSNational Emission Standards for Hazardous Air Pollutants
NGANatural Gas Act of 1938
NGDNatural gas distribution business
NGLsNatural gas liquids
NGPANatural Gas Policy Act of 1978

iii


GLOSSARY (cont.)
NGPSANatural Gas Pipeline Safety Act of 1968
NRGNRG Energy, Inc.
NYMEXNew York Mercantile Exchange
NYSENew York Stock Exchange
OCCOklahoma Corporation Commission
OGEOGE Energy Corp.
PBRCPerformance Based Rate Change
PHMSAPipeline and Hazardous Materials Safety Administration
PRPsPotentially responsible parties
PUCTPublic Utility Commission of Texas
Railroad CommissionRailroad Commission of Texas
RCRAResource Conservation and Recovery Act of 1976
Reliant EnergyReliant Energy, Incorporated
REPRetail electric provider
RICE MACTReciprocating Internal Combustion Engines Maximum Achievable Control Technology
ROEReturn on equity
RRARate Regulation Adjustment
RRIReliant Resources, Inc.
RSPRate Stabilization Plan
SECSecurities and Exchange Commission
SESHSoutheast Supply Header, LLC
Securitization BondsTransition and system restoration bonds
Enable Series A Preferred UnitsEnable’s 10% Series A Fixed-to-Floating Non-Cumulative Redeemable Perpetual Preferred Units, representing limited partner interests in Enable
Energy ServicesOffered competitive variable and fixed-priced physical natural gas supplies primarily to commercial and industrial customers and electric and natural gas utilities through CES and CEIP
Energy Services Disposal GroupSubstantially all of the businesses within CenterPoint Energy’s and CERC’s Energy Services reporting unit that were sold under the Equity Purchase Agreement
Energy Systems GroupEnergy Systems Group, LLC, a wholly-owned subsidiary of Vectren
Energy TransferEnergy Transfer LP, a Delaware limited partnership
Energy Transfer Common UnitsEnergy Transfer common units, representing limited partner interests in Energy Transfer
Energy Transfer GPLE GP, LLC, a Delaware limited liability company and sole general partner of Energy Transfer
Energy Transfer Series G Preferred UnitsEnergy Transfer Series G Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units, representing limited partner interests in Energy Transfer
EPAEnvironmental Protection Agency
Equity Distribution AgreementEquity Distribution Agreement, dated as of January 10, 2024, by and between CenterPoint Energy, the ATM Managers, the ATM Forward Purchasers and the ATM Forward Sellers
Equity Purchase AgreementEquity Purchase Agreement, dated as of May 21, 2023, by and between Vectren Energy Services and ESG Holdings Group
iii

GLOSSARY
ERCOTElectric Reliability Council of Texas
ERCOT ISOERCOT Independent System Operator
ERISAEmployee Retirement Income Security Act of 1974
ERGEmployee Resource Group
EROElectric Reliability Organization
ESG Holdings GroupESG Holdings Group, LLC a Delaware limited liability company, and an affiliate of Oaktree Capital Management
FACFuel Adjustment Clause
FASBFinancial Accounting Standards Board
February 2021 Winter Storm EventThe extreme and unprecedented winter weather event in February 2021 (also known as Winter Storm Uri) resulting in electricity generation supply shortages, including in Texas, and natural gas supply shortages and increased wholesale prices of natural gas in the United States, primarily due to prolonged freezing temperatures.
FERCFederal Energy Regulatory Commission
FitchFitch Ratings, Inc.
Form 10-KAnnual Report on Form 10-K
FPAFederal Power Act
General MortgageGeneral Mortgage Indenture, dated as of October 10, 2002, between CenterPoint Energy Houston Electric, LLC and JPMorgan Chase Bank, as Trustee, as supplemented
GHGGreenhouse gases
GRIPGas Reliability Infrastructure Program
GWhGigawatt-hours
HLPSAHazardous Liquid Pipeline Safety Act of 1979
Houston ElectricCenterPoint Energy Houston Electric, LLC and its subsidiaries
HVACHeating, ventilation and air conditioning
IBEWInternational Brotherhood of Electrical Workers
ICPAInter-Company Power Agreement
IDEMIndiana Department of Environmental Management
Indiana ElectricOperations of SIGECO’s electric transmission and distribution services, and includes its power generating and wholesale power operations
Indiana GasIndiana Gas Company, Inc., a wholly-owned subsidiary of CERC Corp.
Indiana NorthGas operations of Indiana Gas
Indiana SouthGas operations of SIGECO
Indiana UtilitiesIndiana Electric, Indiana North and Indiana South, collectively
IRAInflation Reduction Act of 2022
IRPIntegrated Resource Plan
IRSInternal Revenue Service
IURCIndiana Utility Regulatory Commission
kVKilovolt
LAMS Asset Purchase AgreementAsset Purchase Agreement, dated as of February 19, 2024, by and among CERC Corp. and the LAMS Buyers
LAMS BuyersDelta Utilities No. LA, LLC, a Delaware limited liability company, Delta Utilities S. LA, LLC, a Delaware limited liability company, Delta Utilities MS, LLC, a Delaware limited liability company, and Delta Shared Services Co., LLC, a Delaware limited liability company
LDCLocal Distribution Company
LIBORLondon Interbank Offered Rate
LNGLiquefied natural gas
Load ShedCurtailing the amount of electricity a TDU can transmit and distribute to its customers
LPSCLouisiana Public Service Commission
LTIPsLong-term incentive plans
MCRAMISO Cost and Revenue Adjustment
iv

GLOSSARY
M&DOTMortgage and Deed of Trust, dated November 1, 1944, between Houston Lighting and Power Company and Chase Bank of Texas, National Association (formerly, South Texas Commercial National Bank of Houston), as Trustee, as amended and supplemented
MergerThe merger of Merger Sub with and into Vectren on the terms and subject to the conditions set forth in the Merger Agreement, with Vectren continuing as the surviving corporation and as a wholly-owned subsidiary of CenterPoint Energy, Inc., which closed on the Merger Date
Merger AgreementAgreement and Plan of Merger, dated as of April 21, 2018, among CenterPoint Energy, Vectren and Merger Sub
Merger DateFebruary 1, 2019
Merger SubPacer Merger Sub, Inc., an Indiana corporation and wholly-owned subsidiary of CenterPoint Energy
MESCenterPoint Energy Mobile Energy Solutions, Inc. (now known as Mobile Energy Solutions, Inc.), previously a wholly-owned subsidiary of CERC Corp.
MGPManufactured gas plant
MISOMidcontinent Independent System Operator
MMBtuOne million British thermal units
MMcfMillion cubic feet
Moody’sMoody’s Investors Service, Inc.
MPUCMinnesota Public Utilities Commission
MPSCMississippi Public Service Corporation
MvaMegavolt amperes
MWMegawatts
Natural GasNatural gas distribution businesses
NECANational Electrical Contractors Association
NERCNorth American Electric Reliability Corporation
NGANatural Gas Act of 1938
NGLsNatural gas liquids
NGPANatural Gas Policy Act of 1978
NGPSANatural Gas Pipeline Safety Act of 1968
NOLsNet operating losses
NRGNRG Energy, Inc.
NYSENew York Stock Exchange
OPEIUOffice & Professional Employees International Union
OridenOriden LLC
OrigisOrigis Energy USA Inc.
OUCCIndiana Office of Utility Consumer Counselor
OVECOhio Valley Electric Corporation
PHMSAPipeline and Hazardous Materials Safety Administration
PIPES ActProtecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2020
PPAPower purchase agreement
PRPsPotentially responsible parties
PTCsProduction Tax Credits
PUCOPublic Utilities Commission of Ohio
PUCTPublic Utility Commission of Texas
Railroad CommissionRailroad Commission of Texas
RCRAResource Conservation and Recovery Act of 1976
RegistrantsCenterPoint Energy, Houston Electric and CERC, collectively
REPRetail electric provider
Restoration Bond CompanyCenterPoint Energy Restoration Bond Company, LLC, a wholly-owned subsidiary of Houston Electric
v

GLOSSARY
RestructuringCERC Corp.’s common control acquisition of Indiana Gas and VEDO from VUH on June 30, 2022
ROEReturn on equity
ROURight of use
RRARate Regulation Adjustment
RSPRate Stabilization Plan
Scope 1 emissionsDirect source of emissions from a company’s operations
Scope 2 emissionsIndirect source of emissions from a company’s energy usage
Scope 3 emissionsIndirect source of emissions from a company’s end-users
SECSecurities and Exchange Commission
Securitization BondsTransition and system restoration bonds issued by the Bond Companies and SIGECO Securitization Bonds issued by the SIGECO Securitization Subsidiary
Series A Preferred StockCenterPoint Energy’s previously outstanding Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Stock, par value $0.01 per share, with a liquidation preference of $1,000 per share
Series B Preferred StockCenterPoint Energy’s previously outstanding 7.00% Series B Mandatory Convertible Preferred Stock, par value $0.01 per share, with a liquidation preference of $1,000 per share
Series C Preferred StockCenterPoint Energy’s previously outstanding Series C Mandatory Convertible Preferred Stock, par value $0.01 per share, with a liquidation preference of $1,000 per share
SIGECOSouthern Indiana Gas and Electric Company, a wholly-owned subsidiary of Vectren
SIGECO Securitization BondsSIGECO Securitization Subsidiary’s Series 2023-A Senior Secured Securitization Bonds
SIGECO Securitization SubsidiarySIGECO Securitization I, LLC, a direct, wholly-owned subsidiary of SIGECO
SOFRSecured Overnight Financing Rate
S&PStandard & Poor’sS&P Global Ratings, Services, a division of The McGraw-Hill CompaniesS&P Global Inc.
TBDSRCSales Reconciliation Component
TBDTo be determined
TCEH Corp.Formerly Texas Competitive Electric Holdings Company LLC, predecessor to Vistra Energy Corp. whose major subsidiaries include Luminant and TXU Energy
TCJATax reform legislation informally called the Tax Cuts and Jobs Act of 2017
TCOSTransmission Cost of Service
TDUTCRFTransmission Cost Recovery Factor
TDSICTransmission, Distribution and Storage System Improvement Charge
TDUTransmission and distribution utility
TimeTEEEFTime Inc.
Time CommonTime common stock
Transition AgreementsServices Agreement, Employee Transition Agreement, Transitional Seconding Agreement and other agreements entered into in connection withAssets leased or costs incurred as “temporary emergency electric energy facilities” under Section 39.918 of the formation of EnablePublic Utility Regulatory Act, also referred to as mobile generation
Texas RETexas Reliability Entity
TWTopic 326Time Warner Inc.Accounting Standards Update 2016-13 - Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments
TW Common
TSATW common stockTransportation Security Administration
TWC
USWTime Warner Cable Inc.United Steelworkers Union
TWC CommonUWUATWC common stockUtility Workers Union of America
TW SecuritiesUtility HoldingCharter Common, Time Common and TW CommonUtility Holding, LLC, a wholly-owned subsidiary of CenterPoint Energy
VaR
VectrenValue at Risk

iv


Vectren, LLC, which converted its corporate structure from Vectren Corporation to a limited liability company on June 30, 2022, a wholly-owned subsidiary of CenterPoint Energy as of the Merger Date, and, after the Restructuring, is held indirectly by CenterPoint Energy through Vectren Affiliated Utilities, Inc.
Vectren Energy ServicesVectren Energy Services Corporation, an Indiana corporation and a wholly-owned subsidiary of CenterPoint Energy
GLOSSARY (cont.)VEDOVectren Energy Delivery of Ohio, LLC, which converted its corporate structure from Vectren Energy Delivery of Ohio, Inc. to a limited liability company on June 13, 2022, formerly a wholly-owned subsidiary of Vectren, acquired by CERC on June 30, 2022
VerizonVIEVerizon Communications, Inc.
VIEVariable interest entity
Vistra Energy Corp.Texas-based energy company focused on the competitive energy and power generation marketsmarkets.
ZENSVRPVoluntary Remediation Program
vi

GLOSSARY
VUHVectren Utility Holdings, LLC, which converted its corporate structure from Vectren Utility Holdings, Inc. to a limited liability company on June 30, 2022, a wholly-owned subsidiary of Vectren
WBD CommonWarner Bros. Discovery, Inc. Series A common stock
Winter Storm ElliottFrom December 21 to 26, 2022, a historic extratropical cyclone created winter storm conditions, including blizzards, high winds, snowfall and record cold temperatures across the majority of the United States and parts of Canada.
ZENS2.0% Zero-Premium Exchangeable Subordinated Notes due 2029
2002 ActZENS-Related SecuritiesPipeline Safety Improvement ActAs of 2002December 31, 2023 and December 31, 2022, consisted of AT&T Common, Charter Common and WBD Common
2006 Act2022 Form 10-KPipeline Inspection, Protection, Enforcement and Safety Act of 2006Annual Report on Form 10-K for the fiscal year ended December 31, 2022
2011 Act2022 Annuity Lift-OutPipeline Safety, Regulatory Certainty, and Job Creation ActThe irrevocable group annuity contract purchased in December 2022 from an insurance company to transfer $138 million of 2011
2016 Act
Protecting our Infrastructure of Pipelines and Enhancing Safety Act
of 2016
CenterPoint Energy’s pension plan’s outstanding benefit obligation


v
vii



CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION


From time to time wethe Registrants make statements concerning ourtheir expectations, beliefs, plans, objectives, goals, strategies, future events or performance and underlying assumptions and other statements that are not historical facts. These statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Actual results may differ materially from those expressed or implied by these statements. You can generally identify our forward-looking statements by the words “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecast,” “goal,” “intend,” “may,” “objective,” “plan,” “potential,” “predict,” “projection,” “should,” “target,” “will” or other similar words.


WeThe Registrants have based ourtheir forward-looking statements on our management’s beliefs and assumptions based on information reasonably available to our management at the time the statements are made. WeThe Registrants caution you that assumptions, beliefs, expectations, intentions and projections about future events may and often do vary materially from actual results. Therefore, wethe Registrants cannot assure you that actual results will not differ materially from those expressed or implied by ourthe Registrants’ forward-looking statements. In this Form 10-K, unless context requires otherwise, the terms “our,” “we” and “us” are used as abbreviated references to CenterPoint Energy, Inc. together with its consolidated subsidiaries, including Houston Electric, CERC and SIGECO.


Some of the factors that could cause actual results to differ from those expressed or implied by ourthe Registrants’ forward-looking statements are described under “Risk Factors” in Item 1A and “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Certain Factors Affecting Future Earnings” and “ — Liquidity and Capital Resources — Other Matters — Other Factors That Could Affect Cash Requirements” in Item 7 of Part II of this report, which discussions are incorporated herein by reference.


You should not place undue reliance on forward-looking statements. Each forward-looking statement speaks only as of the date of the particular statement, and wethe Registrants undertake no obligation to update or revise any forward-looking statements.
 

SUMMARY OF RISK FACTORS

An investment in CenterPoint Energy’s securities involves a significant degree of risk. Below is a summary of certain risk factors to consider in evaluating CenterPoint Energy as well as its Common Stock. However, this list is not exhaustive. Before investing in CenterPoint Energy, carefully consider the risk factors discussed or referenced below and in Item 1A. “Risk Factors” of this combined report on Form 10-K. If any of the risks discussed below and in Item 1A. “Risk Factors” were actually to occur, CenterPoint Energy’s, Houston Electric’s and CERC’s business, financial condition, results of operations or cash flows could be adversely affected. In that case, CenterPoint Energy might not be able to pay dividends on its Common Stock, or the trading price of its Common Stock could decline.

Risk Factors Affecting Operations

Electric Generation, Transmission and Distribution (CenterPoint Energy and Houston Electric)

•Disruptions at power generation facilities, generation inadequacy or directives issued by regulatory authorities could cause interruptions in Houston Electric’s and Indiana Electric’s ability to provide transmission and distribution services and adversely affect their reputation, financial condition, results of operations and cash flows.
•Houston Electric’s receivables are primarily concentrated in a small number of REPs, and any delay or default in payments of these receivables could adversely affect Houston Electric’s financial condition, results of operations and cash flows.
•Indiana Electric’s execution of its generation transition plan, including its IRP, is subject to various risks, including timely recovery of capital investments and increased costs and risks related to the timing and cost of development and/or construction of new generation facilities.
•The occurrence of extreme weather events, including winter storms and record hot temperatures, or other causes could lead to additional reforms to the Texas electric market, some measure of which, if implemented, could have an adverse impact on Houston Electric.
•Houston Electric’s use of TEEEF is subject to various risks, including failure to obtain and deploy sufficient TEEEF resources, potential performance issues and allegations about Houston Electric’s deployment of the resources (including the planning, execution and effectiveness of the same), regulatory and environmental requirements, and timely recovery of capital.

vi
viii

Natural Gas (CenterPoint Energy and CERC)

•Access to natural gas supplies and pipeline transmission and storage capacity are essential components of reliable service for Natural Gas’ customers.
•Natural Gas is subject to fluctuations in natural gas prices, which could affect the ability of its suppliers and customers to meet their obligations or may impact its operations, which could adversely affect CERC’s financial condition, results of operations and cash flows.
•Natural Gas must compete with alternate energy sources, which could result in less natural gas delivered and have an adverse impact on CenterPoint Energy’s and CERC’s financial condition, results of operations and cash flows.

Risk Factors Affecting Regulatory, Environmental and Legal Risks

•Rate regulation of Registrants’ Electric and Natural Gas businesses may delay or deny their ability to earn an expected return and fully and timely recover their costs.
•We are subject to operational and financial risks and liabilities arising from environmental laws and regulations, including regulation of CCR, climate change legislation and certain local initiatives that seek to limit fossil fuel usage.
•CenterPoint Energy is subject to operational and financial risks and liabilities associated with the implementation of and efforts to achieve its carbon emissions reduction goals.
•We are involved in numerous legal proceedings, the outcomes of which are uncertain, and resolution adverse to us could negatively affect our financial results.

Risk Factors Affecting Financial, Economic and Market Risks

•Disruptions to the global supply chain may lead to higher prices for goods and services and impact our operations, which could have an adverse impact on our ability to execute our capital plan and on our financial condition, results of operations and cash flows.
•CenterPoint Energy is a holding company that derives all of its operating income from, and holds substantially all of its assets through, its subsidiaries. As a result, CenterPoint Energy depends on the performance of and distributions from its subsidiaries to meet its payment obligations and to pay dividends on its common stock, and provisions of applicable law or contractual restrictions could limit the amount of those distributions.
•If we are unable to arrange future financings on acceptable terms, our ability to finance our capital expenditures or refinance outstanding indebtedness could be limited.
•If CenterPoint Energy redeems the ZENS prior to their maturity in 2029, its ultimate tax liability and redemption payments would result in significant cash payments, which would adversely impact its cash flows. Similarly, a significant amount of exchanges of ZENS by ZENS holders could adversely impact CenterPoint Energy’s cash flows.

Risk Factors Affecting Safety and Security Risks

•The Registrants’ businesses have safety risks.
•Cyberattacks, physical security breaches, acts of terrorism or other disruptions could adversely impact our reputation, financial condition, results of operations and cash flows.

General and Other Risks

•Our revenues and results of operations are seasonal.
•Climate change could adversely impact financial results from our businesses and result in more frequent and more severe weather events that could adversely affect our results of operations.
•Aging infrastructure may lead to increased costs and disruptions in operations that could negatively impact our financial results.
•Our businesses will continue to have to adapt to technological change and may not be successful or may have to incur significant expenditures to adapt to technological change.

ix


PART I


Item 1.Business

Item 1.Business

This combined Form 10-K is filed separately by three registrants: CenterPoint Energy, Inc., CenterPoint Energy Houston Electric, LLC and CenterPoint Energy Resources Corp. Information contained herein relating to any individual registrant is filed by such registrant solely on its own behalf. Each registrant makes no representation as to information relating exclusively to the other registrants or the subsidiaries of CenterPoint Energy other than itself or its subsidiaries. Except as discussed in Note 13 to the consolidated financial statements, no registrant has an obligation in respect of any other registrant’s debt securities, and holders of such debt securities should not consider the financial resources or results of operations of any registrant other than the obligor in making a decision with respect to such securities.

The discussion of CenterPoint Energy’s consolidated financial information includes the financial results of Houston Electric and CERC, which, along with CenterPoint Energy, are collectively referred to as the Registrants. Where appropriate, information relating to a specific registrant has been segregated and labeled as such. Unless the context indicates otherwise, specific references to Houston Electric and CERC also pertain to CenterPoint Energy. In this Form 10-K, the terms “our,” “we” and “us” are used as abbreviated references to CenterPoint Energy, Inc. together with its consolidated subsidiaries.

OUR BUSINESS


Overview


We areCenterPoint Energy is a public utility holding company. OurCenterPoint Energy’s operating subsidiaries own and operate electric transmission, distribution and distributiongeneration facilities and natural gas distribution facilities, supplyfacilities.

As of December 31, 2023, CenterPoint Energy’s indirect, wholly-owned subsidiaries include:

•Houston Electric, which provides electric transmission service to transmission service customers in the ERCOT region and distribution service to REPs serving the Texas gulf coast area that includes the city of Houston. Bond Companies are wholly-owned, bankruptcy remote entities formed solely for the purpose of purchasing and owning transition or system restoration property through the issuance of Securitization Bonds.

•CERC Corp., which (i) directly owns and operates natural gas to commercialdistribution systems in Louisiana, Minnesota, Mississippi and industrial customersTexas, (ii) indirectly, through Indiana Gas and VEDO, owns and operates natural gas distribution systems in Indiana and Ohio, respectively, and (iii) owns and operates permanent pipeline connections through interconnects with various interstate and intrastate pipeline companies through CEIP.

•SIGECO, which provides energy delivery services to electric and natural gas utilitiescustomers located in and own interestsnear Evansville in Enable as described below. Our simplified corporate structure is shown below:southwestern Indiana and owns and operates electric generation assets to serve its electric customers and optimizes those assets in the wholesale power market.


(1)HoustonAs of December 31, 2023, CenterPoint Energy’s reportable segments were Electric, engages in the electric transmission and distribution business in the Texas Gulf Coast area that includes the city of Houston.

(2)Bond Companies are wholly-owned, bankruptcy remote entities formed solely for the purpose of purchasing and owning transition or system restoration property through the issuance of Securitization Bonds.

(3)NGD operates natural gas distribution systems in six states.

(4)CES obtains and offers competitive variable and fixed-price physical natural gas supplies and services primarily to commercial and industrial customers and electric and natural gas utilities in 33 states.
(5)Represents limited partner interests in Enable, which owns, operates and develops natural gas and crude oil infrastructure assets. For additional information regarding our interest in Enable, see Note 10 to our consolidated financial statements.



Our reportable business segments are Electric Transmission & Distribution, Natural Gas Distribution, Energy Services, Midstream Investments and Other Operations.Corporate and Other. Houston Electric and CERC each consist of one reportable segment. For a description of CenterPoint Energy’s reportable segments, see Note 17. For a discussion of operatingnet income by segment, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Results of Operations by BusinessReportable Segment” in Item 7 of Part II of this report. For additional information about the segments, see Note 18 to our consolidated financial statements.

Discontinued Operations. From time to time, we consider the acquisition or the disposition of assets or businesses. For a discussion of discontinued operations and divestitures, see Note 4 to the consolidated financial statements.


OurSubsequent Events. 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 local distribution company businesses. The transaction is expected to close in the first quarter of 2025. For further information, see Note 21 to the consolidated financial statements.

The Registrants’ principal executive offices are located at 1111 Louisiana, Houston, Texas 77002 (telephone number: 713-207-1111).


We make available free of charge on our internetInternet website our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the
1

Securities Exchange Act of 1934, as amended, as soon as reasonably practicable after we electronically file such reports with, or furnish them to, the SEC. The SEC maintains an Internet website that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC at http://www.sec.gov. Additionally, we make available free of charge on our Internet website:


•our Code of Ethics for our Chief Executive Officer and Senior Financial Officers;


•our Ethics and Compliance Code;


•our Supplier Code of Conduct;

•our Corporate Governance Guidelines; and


•the charters of the audit, compensation, finance and governance, environmental and sustainability committees of our Board of Directors.


Any shareholder who so requests may obtain a printed copy of any of these documents from us. Changes in or waivers of our Code of Ethics for our Chief Executive Officer and Senior Financial Officers and waivers of our Ethics and Compliance Code for directors or executive officers will be posted on our Internet website within five business days of such change or waiver and maintained for at least 12 months or timely reported on Item 5.05 of Form 8-K.


Our website address is www.centerpointenergy.com.www.centerpointenergy.com. Investors should also note that we announce material financial information in SEC filings, press releases and public conference calls. Based on guidance from the SEC, we may use the investor relations section of our website to communicate with our investors. It is possible that the financial and other information posted there could be deemed to be material information. Except to the extent explicitly stated herein, documents and information on our website are not incorporated by reference herein.


Electric Transmission & Distribution(CenterPoint Energy)

The Electric reportable segment is comprised of Houston Electric and Indiana Electric.

For information regarding the properties of the Electric reportable segment, please read “Properties — Electric (CenterPoint Energy and Houston Electric)” in Item 2 of this report, which information is incorporated herein by reference.

Houston Electric (CenterPoint Energy and Houston Electric)
 
Houston Electric is a transmission and distribution electric utility that operates wholly within the state of Texas and is a member of ERCOT. ERCOT serves as the independent system operator and regional reliability coordinator for member electric power systems in most of Texas. The ERCOT market represents approximately 90% of the demand for power in Texas and is one of the nation’s largest power markets. The ERCOT market operates under the reliability standards developed by the NERC, approved by the FERC and monitored and enforced by the Texas RE. The PUCT has primary jurisdiction over the ERCOT market to ensure the adequacy and reliability of electricity supply across the state’s main interconnected power transmission grid. Neither


Houston Electric nor any other subsidiary of CenterPoint Energy makesdoes not make direct retail or wholesale sales of electric energy or ownsown or operatesoperate any electricpower generation generating facilities. Houston Electric’s service territory is depicted below:facilities other than TEEEF.

Electric Transmission
 
On behalf of REPs, Houston Electric delivers electricity from power plants to substations, from one substation to another and to retail electric customers taking power at or above 69 kV in locations throughout Houston Electric’s certificated service territory. Houston Electric constructs and maintains transmission facilities and provides transmission services under tariffs approved by the PUCT.

The ERCOT ISO is responsible for operating the bulk electric power supply system in the ERCOT market. Houston Electric’s transmission business, along with those of other owners of transmission facilities in Texas, supports the operation of the ERCOT ISO. Houston Electric participates with the ERCOT ISO and other ERCOT utilities to plan, design, obtain regulatory approval for and construct new transmission lines necessary to increase bulk power transfer capability and to remove existing constraints on the ERCOT transmission grid.

Electric Distribution
 
In ERCOT, end users purchase theirHouston Electric’s distribution network receives electricity directly from certificated REPs. Houston Electricthe transmission grid through power distribution substations and delivers electricity for REPs in its certificated service area by carrying lower-voltage power from the substation to the retail electric customer. Houston Electric’s distribution network receives electricity from the transmission grid through power distribution substations and delivers electricity to end userscustomer through distribution feeders. Houston Electric’s operations include construction and maintenance of distribution facilities, metering services, outage response services and call center operations. Houston Electric provides distribution services under tariffs approved by the PUCT. PUCT rules and market protocols govern the commercial operations of distribution companies and other market participants. Rates for these existing services are established pursuant to rate proceedings conducted before municipalities that have original jurisdiction and the PUCT.
2

Bond Companies


Houston Electric has special purpose subsidiaries consisting of the Bond Companies, which it consolidates. TheThese consolidated special purpose subsidiaries are wholly-owned, bankruptcy remote entities that were formed solely for the purpose of purchasing and owning transition or system restoration property through the issuance of Securitization Bonds, and conducting activities incidental thereto. The Securitization Bonds issued by Bond Company IV are repaid through charges imposed on customers in Houston Electric’s service territory. On August 15, 2022, Restoration Bond Company repaid in full its last outstanding system restoration bonds at maturity. For further discussion of the Securitization Bonds issued by Bond Company IV and the outstanding balances as of December 31, 20172023 and 2016,2022, see Note 13 to ourthe consolidated financial statements.


Customers
 
Houston Electric serves nearly all of the Houston/Galveston metropolitan area. At December 31, 2017,area near the Texas gulf coast. Houston Electric’s customers consistedconsist of approximately 68 REPs, which sell electricity to more than 2.4 million metered customers in Houston Electric’s certificated service area, and municipalities, electric cooperatives and other distribution companies located outside Houston Electric’s certificated service area. Each REP is licensed by, and must meet minimum creditworthiness criteria established


by, the PUCT. Houston Electric does not have long-term contracts with any of its customers. It operates using a continuous billing cycle, with meter readings being conducted and invoices being distributed to REPs each business day. For information regarding Houston Electric’s major customers, see Note 1817 to ourthe consolidated financial statements.

Utility Technology

The table below reflects the number of REPs and metered customers in Houston Electric’s Smart Grid is comprisedservice area as of the AMS, IG, ADMS and private telecommunications network. Since 2009, Houston Electric has deployed fully operational advanced meters to virtually all of its 2.4 million metered customers, automatedDecember 31, substations, installed 872 IG Switching Devices on more than 200 circuits, built a wireless radio frequency mesh telecommunications network across Houston Electric’s 5,000-square mile footprint, and enabled real-time grid monitoring and control, which leverages information from smart meters and field sensors to manage system events through the ADMS. We believe that the Smart Grid is already improving electric distribution service reliability and restoration, enhancing the consumer experience, supporting the growth of renewable energy and helping the environment by reducing carbon emissions.2023:

 REPsResidentialCommercial/
Industrial		Total Customers
Texas gulf coast65 2,455,309 308,226 2,763,535 

Competition
 
There are no other electric transmission and distribution utilities in Houston Electric’s service area. For another provider of transmission and distribution services to provide such services in Houston Electric’s territory, it would be required to obtain a certificate of convenience and necessity from the PUCT and, depending on the location of the facilities, may also be required to obtain franchises from one or more municipalities. We knowHouston Electric is not aware of noany other party intending to enter this business in Houston Electric’sits service area at this time. Distributed generation (i.e., power generation located at or near the point of consumption) could result in a reduction of demand for Houston Electric’s distribution services but has not been a significant factor to date.
Seasonality
 
A significant portion of Houston Electric’s revenues isare primarily derived from rates that it collects from each REP based on the amount of electricity it delivers on behalf of that REP. Thus, Houston Electric’s revenues and results of operations are subject to seasonality, weather conditions and other changes in electricity usage, with revenues generally being higher during the warmer months.months when more electricity is used for cooling purposes.
Properties
All of Houston Electric’s properties are located in Texas. Its properties consist primarily of high-voltage electric transmission lines and poles, distribution lines, substations, service centers, service wires, telecommunications network and meters. Most of Houston Electric’s transmission and distribution lines have been constructed over lands of others pursuant to easements or along public highways and streets under franchise agreements and as permitted by law.
All real and tangible properties of Houston Electric, subject to certain exclusions, are currently subject to:
the lien of a Mortgage and Deed of Trust (the Mortgage) dated November 1, 1944, as supplemented; and
the lien of a General Mortgage (the General Mortgage) dated October 10, 2002, as supplemented, which is junior to the lien of the Mortgage.

For information related to debt outstanding under the Mortgage and General Mortgage, see Note 13 to our consolidated financial statements.
Electric Lines - Transmission. As of December 31, 2017, Houston Electric owned and operated the following electric transmission lines:
  Circuit Miles
Operating Voltage Overhead Lines Underground Lines
69 kV 271
 2
138 kV 2,198
 24
345 kV 1,219
 —
  3,688
 26



Electric Lines - Distribution.  As of December 31, 2017, Houston Electric owned 28,883 pole miles of overhead distribution lines and 24,662 circuit miles of underground distribution lines.

Substations.  As of December 31, 2017, Houston Electric owned 235 major substation sites having a total installed rated transformer capacity of 64,924 megavolt amperes.
Service Centers.  As of December 31, 2017, Houston Electric operated 14 regional service centers located on a total of 292 acres of land. These service centers consist of office buildings, warehouses and repair facilities that are used in the business of transmitting and distributing electricity.

Franchises
 
Houston Electric holds non-exclusive franchises from certain incorporated municipalities in its service territory. In exchange for the payment of fees, these franchises give Houston Electric the right to use the streets and public rights-of-way of these municipalities to construct, operate and maintain its transmission and distribution system and to use that system to conduct its electric delivery business and for other purposes that the franchises permit. The terms of the franchises, with various expiration dates, typically range from 2030 to 40 years.

3

Indiana Electric (CenterPoint Energy)

Indiana Electric consists of SIGECO’s electric transmission and distribution services, including its power generating and wholesale power operations. As of December 31, 2023, Indiana Electric supplied electric service to the following:
 ResidentialCommercial/IndustrialTotal Customers
Southwestern Indiana133,201 19,292 152,493 

System Load

Total load and the related reserve margin at the time of the system summer peak on August 25, 2023, is presented below in MW, except for reserve margin at peak.
2023
Total load at peak1,020 
Generating capability1,205 
Purchase supply (effective capacity) (1)659 
Interruptible contracts & direct load control4 
Total power supply capacity1,868 
Reserve margin at peak83 %

(1)Indiana Electric procured bi-lateral capacity contracts starting in the 2023-2024 MISO planning year to support the generation transition. These contracts were procured before MISO moved to a seasonal construct, which allowed several generating units to receive accreditation in the summer season that would not have received any accreditation under MISO's previous annual construct. This resulted in a reserve margin that is higher than normal in the summer, but was limited to the summer season.

The winter peak load for the 2022-2023 season of approximately 785 MW occurred on December 23, 2022. 

Solar

Indiana Electric has entered into various PPAs to purchase solar power to meet its future generation needs as reported in the table below.

PPA withLocationExpected Date in ServiceCapacity
(MW)		Term (in Years)
CleneraWarrick County, Indiana2025100 25
OridenVermillion County, Indiana2025185 15
OrigisKnox County, Indiana2025150 20
435 

For further information about Indiana Electric’s solar power activities, see “Item 2. Properties” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Regulatory Matters” in Item 7 of Part II of this report, which discussion is incorporated herein by reference.
Coal Purchases

Coal for coal-fired generating stations has been supplied from operators of nearby coal mines as there are substantial coal reserves in the southern Indiana area. Major suppliers are those that account for greater than 10% of Indiana Electric’s coal purchases. For the year ended December 31, 2023, Sunrise LLC accounted for 98% of Indiana Electric’s coal purchases, with the remaining 2% being purchased from other suppliers.

4

The table below presents information related to coal purchases during the year ended December 31, 2023 and coal inventory as of December 31, 2023.
(In tons, except average cost per ton)
Coal purchased for generating electricity1,945,593 
Coal inventory as of December 31, 2023345,784 
Average cost of coal per ton$55.26

Firm Purchase Supply

Indiana Electric enters into long-term purchase supply agreements to meet its generation needs as disclosed below:

Fuel TypeProviderLocationContract ExpirationCapacity
(MW)
Purchased in 2023
  (in GWh)
Coal
OVEC (1)
Indiana and Ohion/a32 186 
WindBenton County Wind Farm, LLCBenton County, Indiana202830 76 
WindFowler Ridge II Wind Farm, LLCBenton/Tippecanoe Counties, Indiana202950 116 
112 378 

(1)As part of its power portfolio, Indiana Electric is a 1.5% shareholder in the OVEC. Based on its participation in the ICPA between OVEC and its shareholder companies, Indiana Electric has the right to 1.5% of OVEC’s generating capacity output and shares in 1.5% of the operating expenses and debt obligations of OVEC.

MISO Related Activity

Indiana Electric is a member of the MISO, a FERC approved regional transmission organization. The MISO serves the electric transmission needs of much of the Midcontinent region and maintains operational control over Indiana Electric’s electric transmission facilities as well as other utilities in the region. Indiana Electric is an active participant in the MISO energy markets, where it bids its generation into the Day Ahead and Real Time markets and procures power for its retail customers at Locational Marginal Price as determined by the MISO market. MISO-related purchase and sale transactions are recorded using settlement information provided by the MISO. These purchase and sale transactions are accounted for on at least a net hourly position. 

MISO related activity for the year ended December 31, 2023 was as follows:
In GWh
Net purchases (1)
397 
Net sales (2)
510 

(1)Represents volume intervals when purchases from the MISO were in excess of generation sold to the MISO.
(2)Represents volume intervals when sales to the MISO were in excess of purchases from the MISO.

Interconnections

As of December 31, 2023, Indiana Electric had interconnections with Louisville Gas and Electric Company, Duke Energy Shared Services, Inc., Indianapolis Power & Light Company, Hoosier Energy Rural Electric Cooperative, Inc. and Big Rivers Electric Corporation providing the ability to simultaneously interchange approximately 645 MW during peak load periods. Indiana Electric, as required as a member of the MISO, has turned over operational control of the interchange facilities and its own transmission assets to the MISO. Indiana Electric, in conjunction with the MISO, must operate the bulk electric transmission system in accordance with NERC Reliability Standards. As a result, interchange capability varies based on regional transmission system configuration, generation dispatch, seasonal facility ratings and other factors. Indiana Electric is in compliance with reliability standards promulgated by NERC.
5


SIGECO Securitization Subsidiary

SIGECO has a special purpose subsidiary, SIGECO Securitization Subsidiary, which it consolidates. This consolidated special purpose subsidiary is a wholly-owned, bankruptcy remote entity that was formed solely for the purpose of facilitating the securitization financing of qualified costs in the second quarter of 2023 associated with the completed retirement of SIGECO’s A.B. Brown coal generation facilities through the issuance of SIGECO Securitization Bonds. The obligations of the SIGECO Securitization Bonds are repaid through charges imposed on customers in Indiana Electric’s service territory. For further discussion of the SIGECO Securitization Bonds and the outstanding balance as of December 31, 2023, see Note 13 to the consolidated financial statements.

Competition

There are no other electric transmission and distribution utilities in Indiana Electric’s service area. Indiana Electric is a vertically integrated utility that owns the generation, transmission, and distribution components of a utility.

For another provider of transmission and distribution services to provide such services in Indiana Electric’s territory, it would be required to obtain IURC approval of such service territory. Indiana service territory certificates are exclusive. Distributed generation (i.e., power generation located at or near the point of consumption) could result in reduced demand for Indiana Electric’s distribution services but has not been a significant factor to date.

Seasonality

Indiana Electric’s revenues are primarily derived from rates that it collects from customers in its service territory based on the amount of electricity it delivers. Indiana Electric’s revenues and results of operations are subject to seasonality, weather conditions and other changes in electricity usage, with revenues generally being higher during the warmer months when more electricity is used for cooling purposes, and during the cooler months when more electricity is used for heating purposes.

Natural Gas Distribution(CenterPoint Energy and CERC)


CERC Corp.’s NGD engagesCenterPoint Energy’s and CERC’s Natural Gas engage in regulated intrastate natural gas sales to, and natural gas transportation and storage for, approximately 3.5 million residential, commercial, industrial and transportation customers in Arkansas, Louisiana, Minnesota, Mississippi, Oklahomacustomers. CenterPoint Energy’s and Texas. The largest metropolitan areas served in each state by NGD are Houston, Texas; Minneapolis, Minnesota; Little Rock, Arkansas; Shreveport, Louisiana; Biloxi, Mississippi;CERC’s Natural Gas provide permanent pipeline connections through interconnects with various interstate and Lawton, Oklahoma. NGDintrastate pipeline companies through CEIP. CenterPoint Energy’s and CERC’s Natural Gas also provides unregulatedprovided services in Minnesota consisting of residential appliance repair and maintenance services along with HVAC equipment sales. NGD’s service territorysales and home repair protection plans to natural gas customers in Indiana, Mississippi, Ohio and Texas through a third party as of December 31, 2023.

For information regarding the properties of the Natural Gas reportable segment, please read “Properties — Natural Gas (CenterPoint Energy and CERC)” in Item 2 of this report, which information is depicted below:incorporated herein by reference.


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 local distribution company businesses. The transaction is expected to close in the first quarter of 2025. For further information, see Note 21 to the consolidated financial statements.
In 2017, approximately 37% of NGD’s total throughput was to residential customers and approximately 63% was to commercial and industrial and transportation customers.
6

Customers

The table below reflects the number of NGDCenterPoint Energy’s and CERC’s Natural Gas customers by state as of December 31, 2017:2023:
 ResidentialCommercial/
Industrial/Transportation		Total Customers
Indiana (Indiana Gas)597,315 55,171 652,486 
Louisiana230,833 16,204 247,037 
Minnesota848,909 72,634 921,543 
Mississippi122,306 13,140 135,446 
Ohio308,622 24,543 333,165 
Texas1,797,403 111,543 1,908,946 
Total CERC Natural Gas3,905,388 293,235 4,198,623 
Indiana (SIGECO)104,725 10,606 115,331 
Total CenterPoint Energy Natural Gas4,010,113 303,841 4,313,954 
 Residential 
Commercial/
Industrial
 Total Customers
Arkansas378,429
 47,965
 426,394
Louisiana230,084
 16,711
 246,795
Minnesota788,832
 70,178
 859,010
Mississippi113,752
 12,567
 126,319
Oklahoma89,074
 10,758
 99,832
Texas1,612,969
 98,472
 1,711,441
Total NGD3,213,140
 256,651
 3,469,791


The largest metropolitan areas served in each state were Houston, Texas; Minneapolis, Minnesota; Shreveport, Louisiana; Biloxi, Mississippi; Evansville, Indiana; and Dayton, Ohio.


SeasonalityThe table below reflects the percentage of total throughput by customer type for the year ended December 31, 2023.

 CenterPoint EnergyCERC
Residential32 %33 %
Commercial/Industrial and Transportation68 %67 %
Total Throughput100 %100 %

Seasonality

The demand for intrastate natural gas sales to residential customers and natural gas sales and transportation for commercial and industrial customers is seasonal.seasonal and affected by variations in weather conditions. In 2017,2023, approximately 65% and 66%, respectively, of NGD’sCenterPoint Energy’s and CERC’s Natural Gas total throughput occurred in the first and fourth quarters. These patterns reflect the higher demand for natural gas for heating purposes during the colder months.

Supply and Transportation.Transportation

In 2017, NGD2023, CenterPoint Energy’s Natural Gas purchased virtually all of its natural gas supply pursuant to contracts with remaining terms varying from a few months to four years.three-year terms. Major suppliers in 2017 includedare those that account for greater than 10% of CenterPoint Energy’s or CERC’s annual natural gas supply purchases.

Major suppliers of natural gas for the following:year ended December 31, 2023 were as follows:

SupplierPercent of Supply Volumes
Tenaska Marketing Ventures18.0%
Macquarie Energy, LLC12.5%
BP Energy Company/BP Canada Energy Marketing12.1%
Kinder Morgan Tejas Pipeline/Kinder Morgan Texas Pipeline7.4%
CES5.4%
Mieco, Inc.5.0%
Spire Marketing, Inc.4.9%
United Energy Trading, LLC4.7%
Koch Energy Services, LLC4.0%
Cargill2.8%
 CenterPoint EnergyCERC
Tenaska Marketing Ventures, LLC39 %44 %
Macquarie Energy, LLC15 %19 %
Koch Energy Services, LLC8 %10 %
   Total of major suppliers62 %73 %


Numerous other suppliers provided the remaining 23.2%remainder of NGD’sCenterPoint Energy’s and CERC’s natural gas supply requirements. NGD

CenterPoint Energy’s and CERC’s Natural Gas transports itstheir natural gas supplies through various intrastate and interstate pipelines under contracts with remaining terms, including extensions, varying from one to fifteenten years. NGDCenterPoint Energy’s and CERC’s Natural Gas anticipates that these gas supply and transportation contracts will be renewed or replaced prior to their expiration.
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NGD
CenterPoint Energy’s and CERC’s Natural Gas actively engagesengage in commodity price stabilization pursuant to annual gas supply plans presented to and/or filed with each of its state regulatory authorities. These price stabilization activities include use of storage gas and contractually establishing structured prices (e.g., fixed price, costless collars and caps) with ourCenterPoint Energy’s and CERC’s Natural Gas’ physical gas suppliers. ItsTheir gas supply plans generally call for 50–75% of normal winter supplies to be stabilized in some fashion.
The regulations of the states in which NGD operatesCenterPoint Energy’s and CERC’s Natural Gas operate allow itthem to pass through changes in the cost of natural gas, including savings and costs of financial derivatives associated with the index-priced physical supply, to itstheir customers under purchased gas adjustment provisions in itstheir tariffs. Depending upon the jurisdiction, the purchased gas adjustment factors are updated periodically, ranging from monthly to semi-annually. The changes in the cost of gas billed to customers are subject to review by the applicable regulatory bodies.
NGD usesCenterPoint Energy’s and CERC’s Natural Gas use various third-party storage services or owned natural gas storage facilities to meet peak-day requirements and to manage the daily changes in demand due to changes in weather. NGDCenterPoint Energy’s and CERC’s Natural Gas may also supplement contracted supplies and storage from time to time with stored LNG and propane-air plant production.
NGD owns and operates an underground natural gas storage facility with a capacity of 7.0 Bcf. It has a working capacity of 2.0 Bcf available for use during the heating season and a maximum daily withdrawal rate of 50 MMcf. It also owns eight propane-air plants with a total production rate of 180,000 Dth per day and on-site storage facilities for 12 million gallons of propane (1.0 Bcf natural gas equivalent). It owns a LNG plant facility with a 12 million-gallon LNG storage tank (1.0 Bcf natural gas equivalent) and a production rate of 72,000 Dth per day.

On an ongoing basis, NGD entersCenterPoint Energy’s and CERC’s Natural Gas enter into contracts to provide sufficient supplies and pipeline capacity to meet itstheir customer requirements. However, it is possible for limited service disruptions to occur from time to time due to weather conditions, transportation constraints and other events. As a result of these factors, supplies of natural gas may become unavailable from time to time, or prices may increase rapidly in response to temporary supply constraints or other factors.
NGD currently hasCenterPoint Energy’s and CERC’s Natural Gas businesses continue to utilize AMAs associated with itstheir utility distribution service in Arkansas,Indiana, Louisiana, Minnesota, Mississippi Oklahoma and Texas.  The AMAs have varying terms, the longest of which expires in 2020. Generally, AMAs are contracts between NGDCenterPoint Energy’s and CERC’s Natural Gas and an asset manager that are intended to transfer the working capital obligation and maximize the utilization of the assets. In these


agreements, NGDCenterPoint Energy’s and CERC’s Natural Gas agrees to release transportation and storage capacity to other parties to manage natural gas storage, supply and delivery arrangements for NGDCenterPoint Energy’s and CERC’s Natural Gas and to use the released capacity for other purposes when it is not needed for NGD. NGD is compensated byCenterPoint Energy’s and CERC’s Natural Gas. CenterPoint Energy’s and CERC’s Natural Gas may receive compensation from the asset manager through payments made over the life of the agreements based in part on the results of the asset optimization.  NGDAMAs. CenterPoint Energy’s and CERC’s Natural Gas has an obligation to purchase itstheir winter storage requirements that have been released to the asset manager under these AMAs. NGD has received approval fromThe AMAs have varying terms, the state regulatory commissionslongest of which expires in Arkansas, Louisiana, Mississippi and Oklahoma2029. Pursuant to retain a sharethe provisions of the AMA proceeds.

Assets
As of December 31, 2017, NGD owned approximately 75,000 linear milesagreements, CenterPoint Energy’s and CERC’s Natural Gas either sells natural gas to the asset manager and agrees to repurchase an equivalent amount of natural gas distribution mains, varying in size from one-half inch to 24 inches in diameter. Generally, in each ofthroughout the cities, towns and rural areas served by NGD, it owns the underground gas mains and service lines, metering and regulating equipment located on customers’ premises and the district regulating equipment necessary for pressure maintenance. With a few exceptions, the measuring stations at which NGD receives gas are owned, operated and maintained by others, and its distribution facilities beginyear at the outlet ofsame cost, or simply purchases its full natural gas requirements at each delivery point from the measuring equipment. These facilities, including odorizing equipment, are usually located on land owned by suppliers.asset manager. For amounts outstanding under these AMAs, see Note 13 to the consolidated financial statements.


Competition
 
NGD competesCenterPoint Energy’s and CERC’s Natural Gas compete primarily with alternate energy sources such as electricity and other fuel sources. In some areas, intrastate pipelines, other gas distributors and marketers also compete directly for gas sales to end users. In addition, as a result of federal regulations affecting interstate pipelines, natural gas marketers operating on these pipelines may be able to bypass NGD’sCenterPoint Energy’s and CERC’s Natural Gas’ facilities and market, and sell and/or transport natural gas directly to commercial and industrial customers.


Energy ServicesCorporate and Other (CenterPoint Energy)


CERC offers competitive variableCenterPoint Energy’s Corporate and fixed-priced physical natural gas supplies primarily to commercial and industrial customers and electric and natural gas utilities through CES and its subsidiary, CEIP. Energy Services’ service territory is depicted below:
In 2017, CES marketed approximately 1,200 Bcf of natural gas, related energy services and transportation to approximately 31,000 customers (including approximately 21 Bcf to affiliates) in 33 states. CES customers vary in size from small commercial customers to large utility companies. Not included in the 2017 customer count are approximately 72,000 natural gas customers that are served under residential and small commercial choice programs invoiced by their host utility.  These customers are not included in customer count so as not to distort the significant margin impact from the remaining customer base.


In January 2017, CES completed the acquisition of AEM, providing CES with a portfolio of industrial and large commercial customers complementary to CES’s existing customer base and strategically aligned storage and transportation assets. For further information related to this acquisition, see Note 4 to our consolidated financial statements.
CES offers a variety of natural gas management services to gas utilities, large industrial customers, electric generators, smaller commercial and industrial customers, municipalities, educational institutions, government facilities and hospitals. These services include load forecasting, supply acquisition, daily swing volume management, invoice consolidation, storage asset management, firm and interruptible transportation administration and forward price management. CES also offers a portfolio of physical delivery services designed to meet customers’ supply and price risk management needs. These customers are served directly, through interconnects with various interstate and intrastate pipeline companies, and portably, through our mobile energy solutions business.
In addition to offering natural gas management services, CES procures and optimizes transportation and storage assets. CES maintains a portfolio of natural gas supply contracts and firm transportation and storage agreements to meet the natural gas requirements of its customers. CES aggregates supply from various producing regions and offers contracts to buy natural gas with terms ranging from one month to over five years. In addition, CES actively participates in the spot natural gas markets in an effort to balance daily and monthly purchases and sales obligations. Natural gas supply and transportation capabilities are leveraged through contracts for ancillary services including physical storage and other balancing arrangements.

As described above, CES offers its customers a variety of load following services. In providing these services, CES uses its customers’ purchase commitments to forecast and arrange its own supply purchases, storage and transportation services to serve customers’ natural gas requirements. As a result of the variance between this forecast activity and the actual monthly activity, CES will either have too much supply or too little supply relative to its customers’ purchase commitments. These supply imbalances arise each month as customers’ natural gas requirements are scheduled and corresponding natural gas supplies are nominated by CES for delivery to those customers. CES’s processes and risk control environment are designed to measure and value imbalances on a real-time basis to ensure that CES’s exposure to commodity price risk is kept to a minimum. The value assigned to these imbalances is calculated daily and is known as the aggregate VaR.
Our risk control policy, which is overseen by our Risk Oversight Committee, defines authorized and prohibited trading instruments and trading limits. CES is a physical marketer of natural gas and uses a variety of tools, including pipeline and storage capacity, financial instruments and physical commodity purchase contracts, to support its sales. CES optimizes its use of these various tools to minimize its supply costs and does not engage in speculative commodity trading. The VaR limit within which CES currently operates, a $4 million maximum set by the Board of Directors, is consistent with CES’s operational objective of matching its aggregate sales obligations (including the swing associated with load following services) with its supply portfolio in a manner that minimizes its total cost of supply. In 2017, CES’s VaR averaged $0.7 million with a high of $1.8 million.

Assets
As of December 31, 2017, CEIP owned and operated over 200 miles of intrastate pipeline in Louisiana and Texas. In addition, CES leases transportation capacity on various interstate and intrastate pipelines and storage to service its shippers and end users.
Competition

CES competes with regional and national wholesale and retail gas marketers, including the marketing divisions of natural gas producers and utilities. In addition, CES competes with intrastate pipelines for customers and services in its market areas.

Midstream Investments

Our Midstream Investments business segmentOther consists of CERC Corp.’s equity method investment in Enable. Enable is a publicly traded MLP, jointly controlled by CERC Corp.corporate support operations that support CenterPoint Energy’s business operations and OGE. 

Enable. Enable was formed to own, operate and develop midstream energy infrastructure assets strategically located to serve its customers. Enable’s assets and operations are organized into two reportable segments: (i) gathering and processing and (ii) transportation and storage. Enable’s gathering and processing segment primarily provides natural gas and crude oil gathering and natural gas processing services to its producer customers. Enable’s transportation and storage segment provides interstate and intrastate natural gas pipeline transportation and storage services primarily to its producer, power plant, local distribution company and industrial end-user customers.

Enable’s Gathering and Processing segment. Enable owns and operates substantial natural gas and crude oil gathering and natural gas processing assets in five states. Enable’s gathering and processing operations consist primarily of natural gas gathering


and processing assets serving the Anadarko, Arkoma and Ark-La-Tex Basins and crude oil gathering assets serving the Williston Basin. Enable provides a variety of services to the active producers in its operating areas, including gathering, compressing, treating, and processing natural gas, fractionating NGLs, and gathering crude oil and produced water. Enable serves shale and other unconventional plays in the basins in which it operates.

Enable’s gathering and processing systems compete with gatherers and processors of all types and sizes, including those affiliated with various producers, other major pipeline companies and various independent midstream entities. In the process of selling NGLs, Enable competes against other natural gas processors extracting and selling NGLs. Enable’s primary competitors are other midstream companies who are active in the regions where it operates. Competition to gather crude oil and produced water is primarily a function of rates, terms of service, system reliability and construction cycle time. The rates and terms of service of Enable’s crude oil gathering, but not its produced water gathering, are FERC regulated. Enable’s Williston Basin gathering systems compete with other gatherers, including those affiliated with producers and other midstream companies.

Enable’s Transportation and Storage segment. Enable owns and operates interstate and intrastate transportation and storage systems across nine states. Enable’s transportation and storage systems consist primarily of its interstate systems, its intrastate system and its investment in SESH. Enable’s transportation and storage assets transport natural gas from areas of production and interconnected pipelines to power plants, local distribution companies and industrial end users as well as interconnected pipelines for delivery to additional markets. Enable’s transportation and storage assets also provide facilities where natural gas can be stored by customers.

Enable’s interstate pipelines compete with a variety of other interstate and intrastate pipelines across its operating areas. Enable’s intrastate pipeline competes with a variety of interstate and intrastate pipelines in providing transportation and storage services, including several pipelines with which it interconnects. Enable’s management views the principal elements of competition among pipelines as rates and terms, flexibility and reliability of service.

For information related to CERC Corp.’s equity method investment in Enable, see Notes 2(c), 10 and 19 to our consolidated financial statements.

Other Operations

Our Other Operations business segment includes office buildings and other real estate used in ourfor business operationsoperations. CenterPoint Energy’s Corporate and other corporate operations that support allOther also consisted of our business operations.energy performance contracting and sustainable infrastructure services by Energy Systems Group through June 30, 2023, the date of the sale of Energy Systems Group.


REGULATION


WeThe Registrants are subject to regulation by various federal, state and local governmental agencies, including the regulations described below. The following discussion is based on regulation in the Registrants’ businesses as of December 31, 2023.


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Federal Energy Regulatory Commission


The FERC has jurisdiction under the NGA and the NGPA, as amended, to regulate the transportation of natural gas in interstate commerce and natural gas sales for resale in interstate commerce that are not first sales. The FERC regulates, among other things, the construction of pipeline and related facilities used in the transportation and storage of natural gas in interstate commerce, including the extension, expansion or abandonment of these facilities. TheFERC also regulates the transmission and wholesale sales of electricity in interstate commerce, mergers, acquisitions and corporate transactions by electricity companies, energy markets, reliability standards and the issuance of short-term debt by public utilities regulated by FERC. FERC has authority to prohibit market manipulation in connection with FERC-regulated transactions, to conduct audits and investigations, and to impose significant civil and criminal penalties (up to approximately $1.6 million per day per violation, subject to periodic adjustment to account for inflation) for statutory violations and violations of the FERC’s rules or orders. Our Energy Services business segment markets natural gas in interstate commerce pursuant

Indiana Electric is a “public utility” under the FPA and is subject to blanket authority grantedregulation by the FERC.

Houston Electric is not a “public utility” under the Federal Power ActFPA and, therefore, is not generally regulated by the FERC, although certain of its transactions are subject to limited FERC jurisdiction. The FERC has certain responsibilities with respect to ensuring the reliability of electric transmission service, including transmission facilities owned by Houston Electric and other utilities within ERCOT. The FERC has designated the NERC as the ERO to promulgate standards, under FERC oversight, for all owners, operators and users of the bulk power system (Electric Entities).system. The ERO and the FERC have authority to (a) impose fines and other sanctions on Electric Entitiesapplicable entities that fail to comply with approved standards and (b) audit compliance with approved standards. The FERC has approved the delegation by the NERC of authority for reliability in ERCOT to the Texas RE.RE and in MISO to ReliabilityFirst Corporation. Neither Houston Electric does notnor Indiana Electric anticipate that the reliability standards proposed by the NERC and approved by the FERC will have a material adverse impact on itstheir operations. To the extent that Houston Electric isand Indiana Electric are required to make additional expenditures to comply with these standards, it is anticipated that Houston Electric and Indiana Electric will seek to recover those costs through the transmission charges that are imposed on all distribution service providers within ERCOT and the MISO, respectively, for electric transmission provided.




As a public utility holding company, under the Public Utility Holding Company Act of 2005, weCenterPoint Energy and ourits consolidated subsidiaries are subject to reporting and accounting requirements and are required to maintain certain books and records and make them available for review by the FERC and state regulatory authorities in certain circumstances.


For a discussion of the Registrants’ ongoing regulatory proceedings, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Regulatory Matters” in Item 7 of Part II of this report, which discussion is incorporated herein by reference.

State and Local Regulation – Electric Transmission & Distribution (CenterPoint Energy and Houston Electric)


Houston Electric is a member of ERCOT, which serves as the independent system operator and regional reliability coordinator for member electric power systems in most of Texas. The ERCOT market represents approximately 90% of the demand for power in Texas and is one of the nation’s largest power markets. The ERCOT market operates under the reliability standards developed by NERC, approved by FERC and monitored and enforced by the Texas RE. The PUCT has primary jurisdiction over the ERCOT market to ensure the adequacy and reliability of electricity supply across the state’s main interconnected power transmission grid.

The ERCOT ISO is responsible for operating the bulk electric power supply system in the ERCOT market. Houston Electric’s transmission business, along with those of other owners of transmission facilities in Texas, supports the operation of the ERCOT ISO. Houston Electric participates with the ERCOT ISO and other ERCOT utilities to plan, design, obtain regulatory approval for and construct new transmission lines necessary to increase bulk power transfer capability and to remove existing constraints on the ERCOT transmission grid.

Houston Electric conducts its operations pursuant to a certificate of convenience and necessityCCN issued by the PUCT that covers its present service area and facilities. The PUCT and certain municipalities have the authority to set the rates and terms of service provided by Houston Electric under cost-of-service rate regulation. Houston Electric holds non-exclusive franchises from certain incorporated municipalities in its service territory. In exchange for payment of fees, these franchises give Houston Electric the right to use the streets and public rights-of-way of these municipalities to construct, operate and maintain its transmission and distribution system and to use that system to conduct its electric delivery business and for other purposes that the franchises permit. The terms of the franchises, with various expiration dates, typically range from 2030 to 40 years.


In ERCOT, end users purchase their electricity directly from certificated REPs. Houston Electric’s distribution rates charged to REPs for residential and small commercial customers are primarily based on amounts of energy delivered, whereas
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distribution rates for a majority of large commercial and industrial customers are primarily based on peak demand. All REPs in Houston Electric’s service area pay the same rates and other charges for transmission and distribution services. This regulated delivery charge includesmay include the transmission and distribution rate (which includes municipal franchise fees), a distribution recoveryDCRF mechanism for recovery of incremental distribution-invested capital above that which is already reflected in the base distribution rate, a TEEEF mechanism for recovery of costs associated with leasing and operating TEEEF, a TCRF mechanism for recovery of approved wholesale transmission cost changes billed by a transmission service provider, a nuclear decommissioning charge associated with decommissioning the South Texas nuclear generating facility, an EECREECRF charge, and charges associated with securitization of regulatory assets, stranded costs and restoration costs relating to Hurricane Ike.costs. Transmission rates charged to distribution companies are based on amounts of energy transmitted under “postage stamp” rates that do not vary with the distance the energy is being transmitted. All distribution companies in ERCOT pay Houston Electric the same rates and other charges for transmission services.


With the IURC’s approval, Indiana Electric is a member of the MISO, a FERC-approved regional transmission organization. The MISO serves the electrical transmission needs of much of the Midcontinent region and maintains operational control over Indiana Electric’s electric transmission and generation facilities as well as those of other utilities in the region. Indiana Electric is an active participant in the MISO energy markets, bidding its owned generation into the Day Ahead and Real Time markets and procuring power for its retail customers at Locational Marginal Pricing as determined by the MISO market. Indiana Electric also receives transmission revenue that results from other members’ use of Indiana Electric’s transmission system. Generally, these transmission revenues, along with costs charged by the MISO, are considered components of base rates and any variance from that included in base rates is recovered from or refunded to retail customers through tracking mechanisms.

For a discussion of certain of Houston Electric’s and Indiana Electric’s ongoing regulatory proceedings, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Regulatory Matters” in Item 7 of Part II of this report, which discussion is incorporated herein by reference.


State and Local Regulation – Natural Gas DistributionElectric Generation (CenterPoint Energy)


In almost all communities in which NGD provides natural gas distribution services,The energy and capacity secured from Indiana Electric’s available generation resources are utilized primarily to serve the needs of retail electric customers residing within Indiana Electric’s franchised service territory. Costs of operating Indiana Electric’s generation facilities are recovered through IURC-approved base rates as well as periodic rate recovery mechanisms including the CECA, ECA, FAC, MCRA, and RCRA mechanism. Costs that are deemed unreasonable or imprudent by the IURC may not be recoverable through retail electric rates. Indiana Electric also receives revenues from the MISO to compensate it operates under franchises, certificates or licenses obtainedfor benefits the generation facilities provide to the transmission system. Proceeds from statethe sales of energy from Indiana Electric’s generation facilities that exceed the requirements of retail customers are shared by Indiana Electric and local authorities. retail electric customers.

The original terms of the franchises, with various expiration dates, typically range from 10 to 30 years, although franchises in Arkansasgeneration facilities owned and operated by Indiana Electric are perpetual. NGD expects to be able to renew expiring franchises. In most cases, franchises to provide natural gas utility services are not exclusive.

Substantially all of NGD is subject to cost-of-service ratevarious environmental regulations enforced by the EPA and the IDEM. Operations of Indiana Electric’s generation facilities are subject to regulation by the relevant state public utility commissionsEPA and in Texas, by the Railroad Commission and those municipalities served by NGD that have retained original jurisdiction. In certainIDEM as it pertains to the discharge of its jurisdictions, NGD has in effect annual rate adjustment mechanisms that provide for changes in rates dependent upon certain changes in invested capital, earned returns on equity or actual margins realized.constituents from the generation facilities. For further discussion, see “Our Business — Environmental Matters” below.

For a discussion of certain of NGD’sIndiana Electric’s ongoing regulatory proceedings, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Regulatory Matters” in Item 7 of Part II of this report, which discussion is incorporated herein by reference.


State and Local Regulation – Natural Gas (CenterPoint Energy and CERC)

In almost all communities in which CenterPoint Energy’s and CERC’s Natural Gas provides natural gas distribution services, they operate under franchises, certificates or licenses obtained from state and local authorities. The original terms of the franchises, with various expiration dates, typically range from 20 to 30 years. CenterPoint Energy’s and CERC’s Natural Gas expects to be able to renew expiring franchises. In most cases, franchises to provide natural gas utility services are not exclusive.

Substantially all of CenterPoint Energy’s and CERC’s Natural Gas is subject to cost-of-service rate regulation by the relevant state public utility commissions and, in Texas, by those municipalities that have retained original jurisdiction. In certain of the jurisdictions in which they operate, CenterPoint Energy’s and CERC’s Natural Gas has annual rate adjustment mechanisms that provide for changes in rates dependent upon certain changes in invested capital, earned returns on equity or actual margins realized.
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For a discussion of certain of CenterPoint Energy’s and CERC’s Natural Gas’ ongoing regulatory proceedings, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Regulatory Matters” in Item 7 of Part II of this report, which discussion is incorporated herein by reference.

Department of Transportation (CenterPoint Energy and CERC)
In December 2006, Congress enacted the 2006 Act, which reauthorized the programs adoptedCenterPoint Energy and CERC are subject to regulation by PHMSA under the 2002 Act. These programs included several requirements relatedNGPSA and the HLPSA. The NGPSA delegated to ensuring pipelinePHMSA through DOT the authority to regulate gas pipelines. The HLPSA delegated to PHMSA through DOT the authority to develop, prescribe and enforce federal safety standards for the transportation of hazardous liquids by pipeline. Every four years PHMSA is up for reauthorization by Congress and a requirement to assess the integrity of pipeline transmission facilities in areas of high population concentration.

Pursuantwith that reauthorization comes changes to the 2006 Act, PHMSA, an agency oflegislative requirements that Congress sets forth for the DOT, issued regulations, effective February 12, 2010, requiring operators of gas distribution pipelines to develop and implement integrity management programs similar to those required for gas transmission pipelines, but tailored to reflect the differences in distribution pipelines. Operatorsoversight of natural gas distribution systems were requiredand hazardous liquid pipelines. In 2020, the PIPES Act was enacted. The PIPES Act reauthorized PHMSA through 2023 and imposed a few new mandates on the agency. The law establishes a PHMSA technology pilot, authorizes a new idled pipe operating status and contains process protections for operators during PHMSA enforcement proceedings. Section 114 of the PIPES Act is a self-mandating rule for natural gas pipeline operations like CERC’s that focuses on processes and procedures to writeeliminate or reduce emissions during normal operations. Further, Section 113 of the PIPES Act directed PHMSA to develop regulations to require natural gas pipeline operators to implement leak detection and implement their integrity managementrepair programs, by August 2, 2011. Ouras well as requirements for mitigating emissions in operations. A proposed rule was published on May 18, 2023. Additional sections of the PIPES Act directed PHMSA to develop regulations requiring natural gas distribution systems met this deadline.



Pursuant to the 2002 Act and the 2006 Act, PHMSA has adopted a number of rules concerning, among other things, distinguishing between gathering lines and transmission facilities, requiring certain design and construction features in new and replaced lines to reduce corrosion and requiring pipeline operators to amend existing written operationsidentify and maintenance proceduresaddress specific risks associated with piping materials with known issues. Over-pressurization, extreme weather and operator qualification programs. PHMSA also updated its reporting requirements for natural gas pipelines effective January 1, 2011.

In December 2011, Congress passed the 2011 Act. This act increased the maximum civil penalties for pipeline safety administrative enforcement actions; required the DOT to study and report on the expansion of integrity management requirements and the sufficiency of existing gathering line regulations to ensure safety; required pipeline operators to verify their records on maximum allowable operating pressure; and imposed newgeohazards require certain actions associated with emergency response and incident notification requirements. In 2016,require operators to identify and maintain certain records associated with system operating characteristics and controls. A proposed rule was published on September 7, 2023. The PIPES Act of 2023 was approved by the 2016 Act reauthorizedHouse Transportation and Infrastructure Committee on December 6, 2023 to reauthorize PHMSA’s pipeline safety programs through 2019for the next four years.

In January 2021, PHMSA published a final rule amending the federal Pipeline Safety Regulations to ease regulatory burdens on the construction, operation, and provided limited new authority, including the ability to issue emergency orders, to set inspection requirements for certain underwater pipelinesmaintenance of gas transmission, distribution, and to promulgate minimum safety standards for natural gas storage facilities, as well as to provide increased transparency into the status of as-yet-incomplete PHMSA actions required by the 2011 Act.gathering systems.


WeCenterPoint Energy and CERC anticipate that compliance with PHMSA’s regulations, performance of the remediation activities by CenterPoint Energy’s and CERC’s natural gas distribution companiesNatural Gas and intrastate pipelines, and verification of records on maximum allowable operating pressure will continue to require increases in both capital expenditures and operating costs. The level of expenditures will depend upon several factors, including age, location and operating pressures of the facilities. In particular, the cost of compliance with the DOT’s integrity management rules will depend on integrity testing and the repairs found to be necessary by such testing. Changes to the amount of pipe subject to integrity management, whether by expansion of the definition of the type of areas subject to integrity management procedures or of the applicability of such procedures outside of those defined areas, may also affect the costs we incur.incurred. Implementation by PHMSA of the 2011 and 2016 Acts byPIPES Act, in particular Section 113, acts reauthorizing PHMSA or other future acts may result in other regulations or the reinterpretation of existing regulations that could impact our compliance costs. In addition, weCenterPoint Energy and CERC may be subject to the DOT’s enforcement actions and penalties if wethey fail to comply with pipeline regulations.


Midstream Investments – Rate and Other Regulation
Federal, state, and local regulation may affect certain aspects of Enable’s business.

Interstate Natural Gas Pipeline Regulation

Enable’s interstate pipeline systems—EGT, MRT and SESH—are subject to regulation by the FERC and are considered “natural gas companies” under the NGA. Under the NGA, the rates for service on Enable’s interstate facilities must be just and reasonable and not unduly discriminatory. Rate and tariff changes for these facilities can only be implemented upon approval by the FERC. Enable’s interstate pipelines business operations may be affected by changes in the demand for natural gas, the available supply and relative price of natural gas in the Mid-continent and Gulf Coast natural gas supply regions and general economic conditions.

Market Behavior Rules; Posting and Reporting Requirements

The EPAct of 2005 amended the NGA to add an anti-manipulation provision that makes it unlawful for any entity to engage in prohibited behavior as prescribed in FERC rules, which were subsequently issued in FERC Order No. 670. The EPAct of 2005 also amends the NGA and the NGPA to give the FERC authority to impose civil penalties for violations of these statutes and FERC’s regulations, rules, and orders, of up to $1.2 million per day per violation, subject to periodic adjustment to account for inflation. Should Enable fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, it could be subject to substantial penalties and fines. In addition, the CFTC is directed under the CEA to prevent price manipulations for the commodity and futures markets, including the energy futures markets. Pursuant to the Dodd-Frank Act and other authority, the CFTC has adopted anti-market manipulation regulations that prohibit fraud and price manipulation in the commodity and futures markets. The CFTC also has statutory authority to seek civil penalties of up to the greater of $1.1 million or triple the monetary gain to the violator for violations of the anti-market manipulation sections of the CEA. These maximum penalty levels are also subject to periodic adjustment to account for inflation.

Intrastate Natural Gas Pipeline and Storage Regulation

Intrastate natural gas transportation is largely regulated by the state in which the transportation takes place. However, an intrastate natural gas pipeline system may transport natural gas in interstate commerce provided that the rates, terms, and conditions of such transportation service comply with Section 311 of the NGPA and Part 284 of the FERC’s regulations. Rates for service pursuant to Section 311 of the NGPA are generally subject to review and approval by the FERC at least once every five years.


Failure to observe the service limitations applicable to transportation services provided under Section 311, failure to comply with the rates approved by the FERC for Section 311 service, or failure to comply with the terms and conditions of service established in the pipeline’s FERC-approved Statement of Operating Conditions could result in the assertion of federal NGA jurisdiction by the FERC and/or the imposition of administrative, civil and criminal penalties, as described under “—Interstate Natural Gas Pipeline Regulation” above.

Natural Gas Gathering and Processing Regulation

Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of the FERC. Although the FERC has not made formal determinations with respect to all of the facilities Enable considers to be gathering facilities, Enable believes that its natural gas pipelines meet the traditional tests that the FERC has used to determine that a pipeline is a gathering pipeline and is therefore not subject to FERC jurisdiction. The distinction, however, has been the subject of substantial litigation, and the FERC determines whether facilities are gathering facilities on a case-by-case basis, so the classification and regulation of Enable’s gathering facilities is subject to change based on future determinations.

States may regulate gathering pipelines. State regulation generally includes various safety, environmental and, in some circumstances, anti-discrimination requirements, and in some instances complaint-based rate regulation. Enable’s gathering operations may be subject to ratable take and common purchaser statutes in the states in which they operate.

Enable’s gathering operations could be adversely affected should they be subject in the future to the application of state or federal regulation of rates and services. Enable’s gathering operations could also be subject to additional safety and operational regulations relating to the design, construction, testing, operation, replacement and maintenance of gathering facilities. We cannot predict what effect, if any, such changes might have on Enable’s operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

Crude Oil Gathering Regulation

Enable provides interstate transportation on its crude oil gathering system in North Dakota pursuant to a public tariff in accordance with FERC regulatory requirements. Crude oil gathering pipelines that provide interstate transportation service may be regulated as a common carrier by the FERC under the ICA, the Energy Policy Act of 1992, and the rules and regulations promulgated under those laws. The ICA and FERC regulations require that rates for interstate service pipelines that transport crude oil and refined petroleum products (collectively referred to as “petroleum pipelines”) and certain other liquids, be just and reasonable and non-discriminatory or not conferring any undue preference upon any shipper. FERC regulations also require interstate common carrier petroleum pipelines to file with the FERC and publicly post tariffs stating their interstate transportation rates and terms and conditions of service.

Safety and Health Regulation

Certain of Enable’s facilities are subject to pipeline safety regulations. PHMSA regulates safety requirements in the design, construction, operation and maintenance of jurisdictional natural gas and hazardous liquid pipeline facilities. All natural gas transmission facilities, such as Enable’s interstate natural gas pipelines, are subject to PHMSA’s regulations, but natural gas gathering pipelines are subject only to the extent they are classified as regulated gathering pipelines. In addition, several NGL pipeline facilities and crude oil pipeline facilities are regulated as hazardous liquids pipelines.

Pursuant to various federal statutes, including the NGPSA, the DOT, through PHMSA, regulates pipeline safety and integrity. NGL and crude oil pipelines are subject to regulation by PHMSA under the Hazardous Liquid Pipeline Safety Act which requires PHMSA to develop, prescribe, and enforce minimum federal safety standards for the transportation of hazardous liquids by pipeline, and comparable state statutes with respect to design, installation, testing, construction, operation, replacement and management of pipeline facilities. Should Enable fail to comply with DOT or comparable state regulations, it could be subject to penalties and fines. If future DOT pipeline regulations were to require that Enable expand its integrity management program to currently unregulated pipelines, costs associated with compliance may have a material effect on its operations.

ENVIRONMENTAL MATTERS


OurThe following discussion is based on environmental matters in the Registrants’ businesses as of December 31, 2023. The Registrants’ operations and the operations of Enable are subject to stringent and complex laws and regulations pertaining to the environment. As an owner or operator of natural gas pipelines, distribution systems and storage, electric transmission and distribution systems, steam electric and renewable generation systems and the facilities that support these systems, wethe Registrants must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact ourthe Registrants’ business activities in many ways, including, but not limited to:




•restricting the way wethe Registrants can handle or dispose of wastes;wastes, including wastewater discharges and air emissions;

•limiting or prohibiting construction activities in sensitive areas such as wetlands, coastal regions or areas inhabited by endangered species;

•requiring remedial action and monitoring to mitigate environmental conditions caused by ourthe Registrants’ operations or attributable to former operations;

•enjoining the operations of facilities with permits issued pursuant to such environmental laws and regulations; and

•impacting the demand for ourthe Registrants’ services by directly or indirectly affecting the use or price of fossil fuels, including, but not limited to, natural gas.


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To comply with these requirements, wethe Registrants may need to spend substantial amounts and devote other resources from time to time to, among other activities:


•construct or acquire new facilities and equipment;

•acquire permits for facility operations;operations or purchase emissions allowances;

•modify, upgrade or replace existing and proposed equipment; and

clean•decommission or decommissionremediate waste management areas, fuel storage facilities and other locations.


Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, revocation of permits, the imposition of remedial actions and monitoring and the issuance of orders enjoining future operations. Certain environmental statutes impose strict, joint and several liability for costs required to assess, clean up and restore sites where hazardous substances have been stored, disposed or released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and/or property damage allegedly caused by the release of hazardous substances or other waste products into the environment.


The recent trend inIncreasingly, environmental regulation has been to placeresulted in more restrictions and limitations on activities that may impact the environment. There can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation and monitoring, and actual future expenditures may be different from the amounts we currently anticipate. Weanticipated. The Registrants try to anticipate future regulatory requirements that might be imposed and plan accordingly to maintain compliance with changing environmental laws and regulations and to ensure the costs of such compliance are reasonable.regulations.


Based on current regulatory requirements and interpretations, wethe Registrants do not believe that compliance with federal, state or local environmental laws and regulations will have a material adverse effect on ourtheir business, financial position, results of operations or cash flows. In addition, wethe Registrants believe that ourtheir current environmental remediation activities will not materially interrupt or diminish ourtheir operational ability. WeThe Registrants cannot assure youprovide assurances that future events, such as changes in existing laws, the promulgation of new laws, or the development or discovery of new facts or conditions will not cause usthem to incur significant costs. The following is a discussion of material current environmental and safety issues, laws and regulations that relate to ourthe Registrants’ operations. WeThe Registrants believe that wethey are in substantial compliance with these environmental laws and regulations.


Global Climate Change


There is increasing attention being paid in the United States and worldwide to the issue of climate change. As a result, from time to time, regulatory agencies have considered the modification of existing laws or regulations or the adoption of new laws or regulations addressing the emissions of GHG on the state, federal, or international level. SomeOn 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 proposalsrule. 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. We will continue to evaluate the applicability of the rule to the existing and new gas-fired generating units, but would note that CenterPoint Energy does not currently have plans to operate any of its coal-fired units beyond December 2029.

The Biden administration recommitted the United States to the Paris Agreement, which has driven a renewed regulatory push to require industrial sourcesfurther GHG emission reductions from the energy sector. On April 22, 2021, President Biden announced new goals of 50% reduction of economy-wide GHG emissions, and 100% carbon-free electricity by 2035, which formed the basis of the United States’ commitments announced in Glasgow, and most recently the international climate negotiations held in Dubai, and concluded in December 2023, included for the first time language in the agreement to meet stringent new standards that would require substantial reductions“transition away from fossil fuels” so as to achieve net zero emissions by 2050.

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
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unregulated market and customers choose their generation providers, CenterPoint Energy’s Scope 2 estimates do not take into account Texas electric transmission and distribution assets in the line loss calculation and, in addition, exclude emissions related to purchased power in Indiana between 2024 and 2026 as estimated. CenterPoint Energy’s Scope 3 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. For more information regarding CenterPoint Energy’s net zero and carbon emission reduction goals and their related risks, see “Risk Factors — Risk Factors Affecting Regulatory, Environmental and Legal Risks — CenterPoint Energy is subject to operational and financial risks ...” 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 itstheir operations or would have the effect of reducing the consumption of natural gas. Our electricThe IRA established the Methane Emissions Reduction Program, which imposes a charge on methane emissions from certain natural gas transmission facilities, and on December 2, 2023, the EPA finalized rules that target reductions in methane emissions, which are likely to increase costs related to production, transmission and distribution business,storage of natural gas. Houston Electric, in contrast to some electric utilities including Indiana Electric, does not generate electricity, other than TEEEF, and thus is not directly exposed to the risk of high capital costs and regulatory uncertainties that face electric utilities that burn fossil fuels to generate electricity. CenterPoint Energy’s net zero emissions goals are aligned with Indiana Electric’s generation transition plan and are expected to position Indiana Electric to comply with anticipated future regulatory requirements related to GHG emissions reductions. Nevertheless, Houston Electric’s and Indiana Electric’s revenues could be adversely affected to the extent any resulting regulatory action has the effect of reducing consumption of electricity by ultimate consumers within itstheir respective service territory.territories. Likewise, incentives to conserve energy or to use energy sources other than natural gas could result in a decrease in demand for the Registrants’ services. For example, Minnesota has enacted the Natural Gas Innovation Act that seeks to provide customers with access to renewable energy resources and innovative technologies, with the goal of reducing GHG emissions.Further, certain local government bodies have introduced or are considering requirements and/or incentives to reduce energy consumption by certain specified dates. For example, Minneapolis has adopted carbon emission reduction goals in an effort to decrease reliance on fossil natural gas. Additionally, cities in Minnesota within CenterPoint Energy’s Natural Gas operational footprint are considering initiatives focused on electrification that could eliminate natural gas use in buildings. 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 services.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 beneficially affectbenefit CenterPoint Energy and CERC and itstheir natural gas-related businesses. At this point in time, however, it would be speculative to try towe cannot quantify the magnitude of the impacts from possible new regulatory actions related to GHG emissions, either positive or negative, on ourthe 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 expects 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.

To the extent climate changes may occur and such climate changes result in warmer temperatures in ourthe Registrants’ service territories, financial results from our and Enable’sthe Registrants’ businesses could be adversely impacted. For example, CenterPoint Energy’s and CERC’s NGDNatural Gas could be adversely affected through lower natural gas sales and Enable’s natural gas gathering, processing and transportation and crude oil gathering businesses could experience lower revenues.sales. On the other hand, warmer temperatures in ourCenterPoint Energy’s and Houston Electric’s electric service territory may increase our revenues from transmission and distribution and generation through increased demand for electricity for cooling. Another possible result of climate change is more frequent and more severe weather events, such as hurricanes, or tornadoes.tornadoes and flooding. Since many of ourthe Registrants’ facilities are located along or near the Gulf Coast,Texas gulf coast, increased or more severe hurricanes or tornadoes could increase our costs to repair damaged facilities and restore service to our customers. When wethe Registrants cannot deliver electricity or natural gas to customers, or our customers cannot receive our services, ourthe Registrants’ financial results can be impacted by lost revenues, and wethey generally must seek approval from regulators to recover restoration costs. To the extent wethe Registrants are unable to recover those costs, or if higher rates resulting from our recovery of such costs result in reduced demand for our services, ourthe Registrants’ future financial results may be adversely impacted.


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Air Emissions


OurThe Registrants’ operations are subject to the federal Clean Air Act and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including electric generating facilities and natural gas processing plants and compressor stations, and also impose various monitoring and reporting requirements. Such laws and regulations may require pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions. WeThe Registrants may be required to obtain and strictly comply with air permits containing various emissions and operational limitations, or utilize specific emission control technologies to limit emissions. Failure to comply with these requirements could result in monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions. WeThe Registrants may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions.

The EPA has established new air emission control requirements for natural gas and NGLs production, processing and transportation activities. Under the NESHAPS, the EPA established the RICE MACT rule. Compressors and back up electrical generators used by our Natural Gas Distribution business segment, and back up electrical generators used by our Electric Transmission & Distribution business segment, are substantially compliant with these laws and regulations.


Water Discharges


OurThe Registrants’ operations are subject to the Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act, and analogous state laws and regulations. These laws and regulations impose detailed requirements and strict controls regarding the discharge of pollutants into waters of the United States. The unpermitted discharge of pollutants, including discharges resulting from a spill or leak incident, is prohibited. The Clean Water Act and regulations implemented thereunder also prohibit discharges of dredged and fill material into wetlands and other waters of the United States unless authorized by an appropriately issued permit. Any unpermitted release of petroleum or other pollutants from ourthe Registrants’ pipelines or facilities could result in fines or penalties as well as significant remedial obligations.


Waters of the United States

Under the Obama administration, the EPA promulgated a set of rules that included a comprehensive regulatory overhaul of defining “waters of the United States” for the purposes of determining federal jurisdiction. These regulations have the potential to affect many aspects of our water-related regulatory compliance obligations. However, the new rules were challenged in court, and the U.S. Supreme Court has recently held that any challenge to the rules must be brought in the U.S. district courts rather than directly before the U.S. courts of appeals. As a result, the new definition of the “waters of the United States” is likely to be disputed in litigation for years to come. Additionally, theThe Trump administration has signaled its intent to repeal and replace the Obama-era rules. Thus,In accordance with this intent, the fate and contentEPA promulgated a rule in early 2018 that postponed the effectiveness of the Obama-era rules until 2020. Thereafter, the EPA proposed a new regulations is currently uncertain,set of rules that would narrow the Clean Water Act’s jurisdiction, which were finalized on April 21, 2020. That set of rules was vacated by decisions in the U.S. federal district courts in New Mexico and it is not clear when,Arizona, and even if, they will be enacted. The potential impacton November 18, 2021, the EPA released a proposal to reestablish the pre-2015 definition of any new “waters of the United States” regulationswhich will become effective upon finalization and publication. On December 30, 2022, the EPA and the U.S. Army Corps of Engineers announced the final “Revised Definition of ‘waters of the United States”’ rule, which was published on our business, liabilities,January 18, 2023 and became effective on March 20, 2023. However, on May 25, 2023, the U.S. Supreme Court issued a decision limiting the scope of federal jurisdiction over wetlands, and on August 29, 2023, the EPA issued a final rule that seeks to conform with the U.S. Supreme Court decision.

ELG

In 2015, the EPA finalized revisions to the existing steam electric wastewater discharge standards which set more stringent wastewater discharge limits and effectively prohibited further wet disposal of coal ash in ash ponds. These new standards are applied at the time of permit renewal and an affected facility must comply with the wastewater discharge limitations no later than December 31, 2023, and the prohibition of wet sluicing of bottom ash no later than December 31, 2025. In February 2019, the IURC approved Indiana Electric’s ELG compliance obligations or profitsplan for its F.B. Culley Generating Station, which was completed in a timely manner and revenuesin compliance with the requirements of ELG.

Cooling Water Intake Structures

Section 316 of the federal Clean Water Act requires steam electric generating facilities use “best technology available” to minimize adverse environmental impacts on a body of water. In May 2014, the EPA finalized a regulation requiring installation of “best technology available” to mitigate impingement and entrainment of aquatic species in cooling water intake structures. Indiana Electric is uncertain at this time.currently completing the required ecological studies and anticipates timely compliance in 2025.


Hazardous Waste


OurThe Registrants’ operations generate wastes, including some hazardous wastes, that are subject to the federal RCRA, and comparable state laws, which impose detailed requirements for the handling, storage, treatment, transport and disposal of hazardous and solid waste. RCRA currently exempts many natural gas gathering and field processing wastes from classification
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as hazardous waste. Specifically, RCRA excludes from the definition of hazardous waste waters produced and other wastes associated with the


exploration, development or production of crude oil and natural gas. However, these oil and gas exploration and production wastes are still regulated under state law and the less stringent non-hazardous waste requirements of RCRA. Moreover, ordinary industrial wastes such as paint wastes, waste solvents, laboratory wastes and waste compressor oils may be regulated as hazardous waste. The transportation of natural gas in pipelines may also generate some hazardous wastes that would be subject to RCRA or comparable state law requirements.


Coal Ash

Indiana Electric has three ash ponds, two at the F.B. Culley facility (Culley East and Culley West) and one at the A.B. Brown facility. In 2015, the EPA finalized its CCR Rule, which regulates coal ash as non-hazardous material under the RCRA. The final rule allows beneficial reuse of ash, and the majority of the ash generated by Indiana Electric’s remaining generating units will continue to be beneficially reused. The EPA continues to propose amendments to the CCR Rule; however, under the CCR Rule as it is currently in effect, Indiana Electric is required to perform integrity assessments, including ground water monitoring, at its F.B. Culley and A.B. Brown generating stations. The ground water studies were necessary to determine the remaining service life of the ponds and whether a pond must be retrofitted with liners or closed in place. Groundwater monitoring indicates potential groundwater impacts adjacent to Indiana Electric’s ash impoundments, and further analysis is ongoing. The CCR Rule required companies to complete location restriction determinations by October 18, 2018. Indiana Electric completed its evaluation and determined that one F.B. Culley pond (Culley East) and the A.B. Brown pond fail the aquifer placement location restriction. As a result of this failure, Indiana Electric was required to cease disposal of new ash in the ponds and commence closure of the ponds by April 11, 2021. Indiana Electric filed timely requests for extensions available under the CCR Rule that would allow Indiana Electric to continue to use the ponds through October 15, 2023. On January 22, 2021, Indiana Electric received letters from the EPA for both the F.B. Culley and A.B. Brown facilities that determined Indiana Electric’s extension submittals complete and extended the compliance deadline of April 11, 2021 until the EPA issues a final decision on the extension requests. On October 5, 2022, SIGECO received a proposed conditional approval of its extension request for the A.B. Brown facility. Both the Culley East and A.B. Brown facility have been taken out of service in a timely manner per the commitments made to the EPA in the extension requests filed for both ponds.The Culley West pond was closed under CCR provisions applicable to inactive ponds, and closure activities were completed in December 2020. For further discussion about Indiana Electric’s ash ponds, please see Note 15(d) to the consolidated financial statements.

On May 18, 2023, the EPA issued a proposed revision to the CCR rule that could potentially expand the scope of units regulated under the federal CCR rule (the CCR “Legacy” rule). The CCR Legacy rule seeks to include legacy CCR surface impoundments (inactive surface impoundments at inactive generating facilities) as well as new “CCR management units” at active or inactive facilities otherwise subject to federal CCR regulations. The potential impact of the CCR Legacy rule is uncertain at this time, and if finalized could require Registrant to conduct additional CCR investigations.

Liability for Remediation


CERCLA, also known as “Superfund,” and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons responsible for the release of “hazardous substances” into the environment. Classes of PRPs include the current and past owners or operators of sites where a hazardous substance was released and companies that disposed or arranged for the disposal of hazardous substances at offsite locations such as landfills. Although petroleum, as well as natural gas, is expressly excluded from CERCLA’s definition of a “hazardous substance,” in the course of ourthe Registrants’ ordinary operations wethey do, from time to time, generate wastes that may fall within the definition of a “hazardous substance.” CERCLA authorizes the EPA and, in some cases, third parties to take action in response to threats to the public health or the environment and to recover the costs they incur from the responsible classes of persons. Under CERCLA, wethe Registrants could potentially be subject to joint and several liability for the costs of cleaning up and restoring sites where hazardous substances have been released, for damages to natural resources, and for associated response and assessment costs, including for the costs of certain health studies.


Liability for Preexisting Conditions


For information about preexisting environmental matters, please see Note 15(d). to the consolidated financial statements.


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EMPLOYEES


HUMAN CAPITAL
As
CenterPoint Energy believes its employees are critical to safely delivering electricity and natural gas across its service territories and seeks to create a diverse, equitable, inclusive and safe work environment. CenterPoint Energy’s core values—safety, integrity, accountability, initiative and respect—guide how it makes decisions and provide the foundation for a strong culture of December 31, 2017, we had 7,977 full-time employees. ethics where employees are responsible for upholding these values and following CenterPoint Energy’s Ethics and Compliance Code.

The following table sets forth the number of our employees by businessRegistrant and reportable segment as of December 31, 2017:2023:
Number of EmployeesNumber of Employees Represented by Collective Bargaining Groups
Reportable SegmentCenterPoint EnergyHouston ElectricCERCCenterPoint EnergyHouston ElectricCERC
Electric3,132 2,781 — 1,659 1,472 — 
Natural Gas3,705 — 3,393 1,695 —1,639 
Corporate and Other (1)
1,990 — — 147 —— 
Total8,827 2,781 3,393 3,501 1,472 1,639 
Business Segment Number 
Number
Represented
by Collective
Bargaining Groups
Electric Transmission & Distribution 2,816
 1,452
Natural Gas Distribution 3,316
 1,200
Energy Services 297
 —
Other Operations 1,548
 127
Total 7,977
 2,779
(1)Employees in the Corporate and Other segment provide services to the Electric and Natural Gas segments and the costs of these services have been charged directly to the Electric and Natural Gas segments using assignment methods that management believes are reasonable. For further information, see Note 19 to the consolidated financial statements.


CenterPoint Energy’s workforce includes 3,501 employees represented by collective bargaining agreements. For information about the status of collective bargaining agreements, see Note 7(f)8(j) to ourthe consolidated financial statements.


Talent Attraction, Development and Retention.CenterPoint Energy’s human capital priorities include attracting, retaining and developing high performing talent through its talent management activities. CenterPoint Energy endeavors to maintain a workforce reflective of the available workforce within the communities we serve by attracting quality candidates through its recruitment and selection processes, with the goal of creating a work environment in which every employee is engaged; aligned with CenterPoint Energy’s strategy, goals and priorities; and understands how they contribute to its long-term performance. CenterPoint Energy recruits qualified employees regardless of race, gender, color, sexual orientation, age, religion, or physical or mental disability. The talent acquisition team has an increased focus with local partnerships to strategically impact all the local communities being served. This continues to include SERJobs, Houston Area Urban League, Work Texas, Wesley Community Center, Historically Black Colleges and Universities, Hispanic Serving Institutions, and a more robust college partnership in all six states in alignment with CenterPoint Energy Foundation initiatives.

CenterPoint Energy takes a strategic approach to attracting, retaining, and developing its workforce. CenterPoint Energy’s strategy combines succession planning along with internal talent development as essential elements of overall workforce development strategy. To support its commitment to safely and reliably delivering electricity and natural gas, CenterPoint Energy focuses on the continuous development of its greatest assets, its employees, building a sustainable leadership pipeline. To meet the business's future needs, CenterPoint Energy’s goal is to create great leaders capable of developing their employees, while supporting the business goals and maintaining a high-performing workforce.CenterPoint Energy has a number of tools for leadership and employee development that expand opportunities available to employees. CenterPoint Energy conducts regular talent discussions, including succession planning with all levels of leadership to provide business continuity and identify its future leaders and opportunities. CenterPoint Energy invests in employee development throughout the year to align performance to business needs, drive development planning and contribute to career progression. CenterPoint Energy’s processes and progress are reviewed regularly for continuous improvement.

Diversity, Equity and Inclusion. CenterPoint Energy is dedicated to advancing an inclusive culture and work environment, free from discrimination of any kind, where business results are achieved through the skills, abilities and talents of a diverse workforce. In 2023, CenterPoint Energy’s DE&I Council continued to focus on the strategic pillars of employee engagement, community and giving, supplier diversity and sustainability, talent acquisition, and customer focus. The DE&I Council has approved eight ERGs with a 123% increase in events that garnered an 87% increase in employee engagement from 2022 to 2023. The ERG events range from professional development podcasts to wellness learnings which are all aligned with CenterPoint Energy’s objectives. These events are available to the employee population. In 2023, CenterPoint Energy and employees continued to be recognized locally, regionally and nationally for enterprise-wide inclusive initiatives. As of December 31, 2023, CenterPoint Energy’s workforce was 42% racially and/or ethnically diverse. Certain members of
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CenterPoint Energy’s executive management team have a negative-only modifier related to diversity metrics that could reduce their short-term incentive compensation.

Compensation and Benefits. CenterPoint Energy is committed to providing its employees with competitive pay and benefits. Its compensation philosophy is to maintain employee total compensation that is competitive with the relevant markets, internally equitable, and based on company and individual performance. CenterPoint Energy expects that this will enable it to attract, motivate and retain employees with the skills and competencies necessary to achieve its business strategy. In addition to competitive compensation, CenterPoint Energy provides its employees with a robust, comprehensive benefits package designed to help employees stay healthy, care for their families, plan for the future and enjoy peace of mind. The benefits package includes medical, dental, vision, life, disability and accidental insurance coverage; retirement, company match savings plans; paid time off, family leave, well-being and employee assistance programs. The employee wellness resources encompass support for mental, financial and physical health.

INFORMATION ABOUT OUR EXECUTIVE OFFICERS
(as of February 9, 2018)
12, 2024)
NameAgeTitle
Jason P. Wells46
NameAgeTitle
Milton Carroll67Executive Chairman
Scott M. Prochazka51President and Chief Executive Officer and Director
William D. RogersChristopher A. Foster4557Executive Vice President and Chief Financial Officer
Tracy B. BridgeLynne Harkel-Rumford6759Executive Vice President and President, Electric Division
Scott E. Doyle46Senior Vice President, Natural Gas Distribution
Joseph J. Vortherms57Senior Vice President, Energy Services
Dana C. O’Brien50Senior Vice President and General Counsel
Sue B. Ortenstone61Senior Vice President and Chief Human Resources Officer
Monica Karuturi45Executive Vice President and General Counsel
Jason M. Ryan48Executive Vice President, Regulatory Services and Government Affairs
Darin Carroll47Senior Vice President, Natural Gas Business
Lynnae Wilson48Senior Vice President, Electric Business


Milton CarrollJason P. Wells has served onas President and Chief Executive Officer of CenterPoint Energy and a member of the Board of Directors of CenterPoint Energy or its predecessors since 1992. He hasJanuary 5, 2024. Previously he served as Executive ChairmanPresident and Chief Operating Officer of CenterPoint Energy since June 2013from May 2023 to January 2024; as President, Chief Operating Officer and Chief Financial Officer of CenterPoint Energy from January 2023 to May 2023; and as Chairman from September 2002 until May 2013. Mr. Carroll has served as a director of Halliburton Company since 2006 and Western Gas Holdings, LLC, the general partner of Western Gas Partners, LP, since 2008. He has served as a director of Health Care Service Corporation since 1998 and as its chairman since


2002. He previously served as a director of LyondellBasell Industries N.V. from July 2010 to July 2016 as well as LRE GP, LLC, the general partner of LRR Energy, L.P., from November 2011 to January 2014.

Scott M. Prochazka has served as a Director andExecutive Vice President and Chief ExecutiveFinancial Officer (CEO) of CenterPoint Energy since January 1, 2014. He previouslyfrom September 2020 to December 2022. Prior to joining CenterPoint Energy, Mr. Wells served as Executive Vice President and Chief OperatingFinancial Officer of PG&E Corporation, a publicly traded electric utility holding company serving customers in Northern and Central California through its subsidiary Pacific Gas and Electric Company, from July 2012June 2019 to December 2013;September 2020. He previously served as Senior Vice President and Division President, Electric OperationsChief Financial Officer of PG&E Corporation from May 2011 through July 2012;January 2016 to June 2019 and as Division Senior Vice President, Business Finance of Pacific Gas and Electric OperationsCompany from August 2013 to January 2016. PG&E Corporation filed Chapter 11 bankruptcy on January 29, 2019 and successfully emerged from bankruptcy on July 1, 2020. He also served in various finance and accounting roles of Houstonincreasing responsibility at Pacific Gas and Electric Company. Mr. Wells earned his bachelor’s degree and master’s degree in accounting, both from February 2009 to May 2011; as Division Senior Vice President, Regional Operationsthe University of CERC from February 2008 to February 2009; and as Division Vice President, Customer Service Operations, from October 2006 to February 2008.Florida. He currentlyis a certified public accountant. Mr. Wells serves on the Boards of Directors of Enable GP, LLC,Executive Committee and Board for the general partner of Enable Midstream Partners, LP, Gridwise Alliance as its Chairman, Edison Electric Institute, Electric Power Research Institute, American Gas Association, Greater Houston Partnership, United WayBauer College Board of the C.T. Bauer College of Business at the University of Houston, Junior Achievementthe Advisory Board of South Texas and the Kinder Institute Advisory Board.for Urban Research at Rice University, and the Boards of Central Houston, Inc. and M.D. Anderson Cancer Center.


William D. RogersChristopher A. Foster has served as Executive Vice President and Chief Financial Officer of CenterPoint Energy since March 2015. He previously served as Executive Vice President, Finance and Accounting from February 2015 to March 2015. Prior to joining CenterPoint Energy, Mr. Rogers was Vice President and Treasurer of American Water Works Company, Inc., the largest publicly traded U.S. water and wastewater utility company, from October 2010 to January 2015. Mr. Rogers was also the Chief Financial Officer of NV Energy, Inc., an investor-owned utility headquartered in Las Vegas serving approximately 1.5 million electric and gas customers in Nevada and with annual revenues of approximately $3 billion, from February 2007 to February 2010. He has previously served as NV Energy’s vice president of finance, risk and tax, as well as corporate treasurer. Before joining NV Energy in June 2005, Mr. Rogers was a managing director in capital markets at Merrill Lynch and prior to that in a similar role at JPMorgan Chase in New York. He currently serves on the Boards of Directors of Enable GP, LLC, the general partner of Enable Midstream Partners, LP, the West Point Association of Graduates and Sheltering Arms of New York.

Tracy B. Bridge May 2023. Previously, has served as Executive Vice President and President,Chief Financial Officer of PG&E Corporation, a publicly traded electric utility holding company serving customers in Northern and Central California through its subsidiary Pacific Gas and Electric DivisionCompany, since February 2014.March 2021. He previously served in various positions of increasing responsibilities at PG&E since 2011, including as Senior Vice President and Division President, Electric OperationsInterim Chief Financial Officer from September 20122020 to February 2014; as SeniorMarch 2021, and Vice President, Treasury and Division President, Gas Distribution OperationsInvestor Relations from May 2011March 2020 to September 2012; as Division Senior Vice President - Support Operations2020. PG&E Corporation filed Chapter 11 bankruptcy on January 29, 2019 and successfully emerged from February 2008 to May 2011; and as Division Vice President Regional Operations of CERCbankruptcy on July 1, 2020. He earned his bachelor’s degree from January 2007 to February 2008.Michigan State University. Mr. Bridge has more than 35 years of utility experience. He currentlyFoster serves as President of the Executive Committee ofon the Board of Directors of Rebuilding Together Houston.Exploratorium, a San Francisco-based science and technology museum.


Scott E. DoyleLynne Harkel-Rumford has served as Senior Vice President, Natural Gas Distribution since March 2017. With more than 20 years of utility experience, he previously served as Senior Vice President, Regulatory and Public Affairs from February 2014 to March 2017; as Division Vice President, Rates and Regulatory from April 2012 to February 2014; and as Division Vice President, Regional Operations from March 2010 to April 2012. Mr. Doyle currently serves on the board of Goodwill Industries of Houston, and he previously served on the boards of the Texas Gas Association and the Association of Electric Companies of Texas.

Joseph J. Vortherms has served as Senior Vice President, Energy Services since March 2017. He previously served as Vice President, Energy Services from November 2015 to March 2017; as Vice President, Regional Operations in Minnesota from October 2014 to November 2015; as Division Vice President, Regional Operations from April 2012 to October 2014; and as Director, Home Service Plus from January 2007 to April 2012. Mr. Vortherms currently serves on the Southern Gas Association Executive Council as well as the American Gas Association Scenario Planning Council. He previously served on the boards of the Minnesota Region American Red Cross and the Minnesota Business Partnership.

Dana C. O’Brien has served as Senior Vice President and General Counsel of CenterPoint Energy since May 2014. Additionally, she served as Corporate Secretary of the Company until October 2017. Before joining CenterPoint Energy, Ms. O’Brien was Chief Legal Officer and Chief Compliance Officer and a member of the executive board at CEVA Logistics, a Dutch-based logistics company, from August 2007 to April 2014.  She previously served as the general counsel at EGL, Inc. from October 2005 to July 2007 and Quanta Services, Inc. from January 2001 to October 2005. Ms. O’Brien serves as a trustee for the Association of Women Attorneys Foundation, as a member of the Board of Directors of Ronald McDonald House Houston and as a member of the Board of Directors of Child Advocates, Inc.

Sue B. Ortenstone has served as Senior Vice President and Chief Human Resources Officer of CenterPoint Energy since FebruaryJanuary 2022. With over 30 years of experience in compensation and benefits matters, Ms. Harkel-Rumford previously served as Senior Vice President and Chief Human Resources Officer from July 2020 to January 2022; Vice President, Total Rewards and Technology from September 2014 to July 2020; and as Associate General Counsel from April 2007 to September 2014. Ms. Harkel-Rumford currently serves on the advisory board of directors of Target Hunger in Houston assisting with Board governance.
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Monica Karuturi has served as Executive Vice President and General Counsel of CenterPoint Energy since January 2022. She previously served as Senior Vice President and General Counsel from July 2020 to January 2022; Senior Vice President and Deputy General Counsel from April 2019 to July 2020; as Vice President and Associate General Counsel - Corporate and Securities from October 2015 to April 2019; and as Associate General Counsel - Corporate from September 2014 to October 2015. Prior to joining CenterPoint Energy, Ms. OrtenstoneKaruturi served as counsel for LyondellBasell Industries for corporate and finance matters and strategic transactions. Ms. Karuturi was appointed as a Commissioner of the Texas Access to Justice Commission by the Texas Supreme Court in June 2015 and served in this capacity until June 2021. She currently serves as Chair of the Houston Bar Foundation.

Jason M. Ryan has served as Executive Vice President, Regulatory Services and Government Affairs of CenterPoint Energy since January 2022. He previously served as Senior Vice President, Regulatory Services and Government Affairs from July 2020 to January 2022; Senior Vice President and Chief Administrative Officer at Copano EnergyGeneral Counsel from April 2019 to July 2012 to May 2013. Before joining Copano, she spent more than 30 years at El Paso Corporation and served most recently2020; as Senior Vice President, Regulatory and then ExecutiveGovernment Affairs from February 2019 to April 2019; as Vice President of Regulatory and Government Affairs and Associate General Counsel from March 2017 to February 2019; and as Vice President and Chief Administrative OfficerAssociate General Counsel from November 2003September 2014 to May 2012. Ms. OrtenstoneMarch 2017. He was appointed to the Texas Diabetes Council by Texas Governor Perry in 2013 for a term ending in 2019; he was reappointed by Texas Governor Abbott in 2019 for a term ending in 2025. Mr. Ryan currently serves on the Industrial Advisoryboards of the Lone Star Flight Museum and the Association of Electric Companies of Texas and on the advisory board of the Strategic AI Program at Houston Christian University. He also serves on the executive committee of the legal committee of the American Gas Association.

Darin Carroll has served as Senior Vice President, Natural Gas Business of CenterPoint Energy since January 2023. He previously served as Senior Vice President, Operations Support from January 2022 to January 2023 and as Vice President, Operations Support from February 2019 to January 2022. Prior to Vectren’s acquisition by CenterPoint Energy, Mr. Carroll served as Director, Operations from February 2014 to February 2019 of Vectren. Mr. Carroll currently serves on the Executive Committee and Board inof Directors of the CollegeJunior Achievement of Engineering atSoutheast Texas, and the Boards of Directors of the American Gas Association and Southern Gas Association. He has also previously been on the Board of Directors of Guardianship Services of Southwestern Indiana and a member of the Indiana Energy Association Gas Operations Committee, Midwest Energy Association Electric Operations Steering Committee, and American Gas Association Field Operations Committee. He earned a bachelor’s degree from the University of Wisconsin,Southern Indiana in Evansville, Indiana.

Lynnae Wilson has served as Senior Vice President, Electric Business of CenterPoint Energy since January 2023. She previously served as Senior Vice President, Houston Electric from January 2022 to January 2023; as Senior Vice President, High Voltage Operations from August 2020 to January 2022; and until October 2017, sheas Chief Business Officer, Indiana Electric, from February 2019 to August 2020. Prior to Vectren’s acquisition by CenterPoint Energy, Ms. Wilson served on the Advisory Board for Civil, Environmental and Geologic Engineering as well.Vice President, Energy Delivery from June 2016 to February 2019 of Vectren. Ms. Ortenstone alsoWilson currently serves on the Board of Trustees for Northwest Assistance Ministriesthe United Way of Houston.Greater Houston and previously served on the Board of ReliabilityFirst Corporation from January 2018 to December 2021.




Item 1A.Risk Factors


Item 1A.Risk Factors

We areCenterPoint Energy is a holding company that conducts all of ourits business operations through subsidiaries, primarily Houston Electric, CERC and CERC. We also own interests in Enable.SIGECO. The following, along with any additional legal proceedings identified or incorporated by reference in Item 3 of this combined report on Form 10-K, summarizes the principal risk factors associated with ourthe holding company and the businesses conducted by our subsidiaries and our interests in Enable.its subsidiaries. However, additional risks and uncertainties either not presently known or not currently believed by management to be material may also adversely affect ourCenterPoint Energy’s businesses. For other factors that may cause actual results to differ from those indicated in any forward-looking statement or projection contained in this combined report on Form 10-K, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Certain Factors Affecting Future Earnings” in Item 7, which should be read in conjunction with the risk factors contained in this Item 1A. Carefully consider each of the risks described below, including those relating to Houston Electric and CERC, which, along with CenterPoint Energy, are collectively referred to as the Registrants. Unless the context indicates otherwise, where appropriate, information relating to a specific registrant has been segregated and labeled as such and specific references to Houston Electric and CERC in this section also pertain to CenterPoint Energy. In this combined report on Form 10-K, the terms “our,” “we” and “us” are used as abbreviated references to CenterPoint Energy, Inc. together with its subsidiaries.

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Risk Factors AssociatedAffecting Operations

Electric Generation, Transmission and Distribution (CenterPoint Energy and Houston Electric)

Disruptions at power generation facilities, generation inadequacy or directives issued by regulatory authorities could cause interruptions in Houston Electric’s and Indiana Electric’s ability to provide transmission and distribution services and adversely affect their reputation, financial condition, results of operations and cash flows.

Houston Electric owns the transmission and distribution infrastructure in its service territory that delivers electric power to its customers, but it does not own or operate any power generation facilities, except for its operation of TEEEF. Indiana Electric owns and operates power generation facilities in addition to the transmission and distribution infrastructure in its service territory. Both Houston Electric and Indiana Electric must follow the directives issued by their respective independent system operator, ERCOT and MISO, respectively. ERCOT and MISO have and may in the future issue directives requiring members to implement controlled outages as a result of an emergency or reliability issues, and Houston Electric has faced and may in the future face challenges to their planning and preparation for such directives and their implementation of Load Shed, including, for example, allegations that they had discretion as to how to shed load and which customers experienced outages and the duration of those outages. As a result, claims and lawsuits could be filed against Houston Electric and Indiana Electric for personal injury, property damage or other damage or loss as a result of their respective Load Shed planning, preparation, implementation, and decisions in order to meet the directives of ERCOT and MISO, respectively. For example, in February 2021, the ERCOT regulated Texas electric system experienced extreme winter weather conditions and an unprecedented power generation shortage. The amount of electricity generated by the state’s power generation companies was insufficient to meet the amount demanded by customers. This resulted in ERCOT directing TDUs to significantly Load Shed, which caused customer outages across the ERCOT electric grid of Texas, including in Houston Electric’s service territory. See Note 7 to the consolidated financial statements and “— Houston Electric’s use of TEEEF ...” for further information. If power generation capacity is severely disrupted or is inadequate for any reason in the future, Houston Electric’s or Indiana Electric’s transmission and distribution services may be diminished or interrupted. Further, as with the lawsuits filed in the aftermath of the February 2021 Winter Storm Event, claims and lawsuits could be filed against the Registrants, and our reputation, financial condition, results of operations and cash flows could be adversely affected.

Additionally, Indiana Electric’s generating facilities and the generating facilities that supply the power transmitted by Houston Electric and Indiana Electric are subject to operational risks that have and may in the future result in unscheduled plant outages, unanticipated operation and maintenance expenses and increased purchase power costs. For example, in June 2022, Culley 3, a coal-fired generation unit, experienced a boiler feed pump turbine failure that caused the unit to be out of service for nearly nine months. In this time frame, CenterPoint Energy purchased energy on the open market and those purchases are currently being challenged at the IURC by multiple intervenors. Such open market purchases have and may again result in increased costs and have an adverse impact on our operations, financial condition, results of operations and cash flows. Further, Indiana Electric is party to a number of PPAs with third parties. Indiana Electric’s power generation may be disrupted or otherwise insufficient if third parties do not deliver required power under our PPAs. These operational risks can arise from circumstances such as facility shutdowns or malfunctions due to equipment failure or operator error; aging infrastructure; interruption of fuel supply or increased prices of fuel as contracts expire and inflation rises; disruptions in the delivery of electricity; inability to comply with regulatory or permit requirements; labor disputes; or natural disasters, all of which could adversely affect Indiana Electric’s and Houston Electric’s businesses. Further, Indiana Electric currently relies on coal for the majority of its generation capacity. Indiana Electric purchases the majority of its coal supply from a single, unrelated party and, although the coal supply is under long-term contract, the loss of this supplier or transportation interruptions could adversely affect its ability to deliver electricity to its customers and adversely impact Indiana Electric’s financial condition, results of operations and cash flows. In 2021 and part of 2022, Indiana Electric experienced coal supply shortages due to labor shortages that the coal industry experienced. While the coal supply shortage that Indiana Electric experienced did not impact its ability to deliver electricity to its customers, labor shortages as well as supply shortages in the future, whether caused by insufficient supply or supplier bankruptcy or other regulatory and supply issues in the mining industry, may lead to increased cost and have an adverse impact on our operations, financial condition, results of operations and cash flows. See “— Disruptions to the global supply...” As Indiana Electric continues its generation transition and more renewable energy sources come online, Indiana Electric’s generating facilities may experience unanticipated disruptions as a result of renewable supply shortages, including, but not limited to, due to cloudy or windless days. Additionally, such disruptions could adversely affect its ability to deliver electricity to its customers and adversely impact Indiana Electric’s financial condition, results of operations and cash flows.

The operations of Houston Electric and Indiana Electric are subject to the usual hazards associated with high-voltage electricity transmission, including inclement weather, natural disasters, mechanical failure, contact with electrified facilities by people, equipment, and debris, unscheduled downtime, equipment interruptions, contamination, remediation, explosions, fires,
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chemical spills, discharges or releases of toxic or hazardous substances, and other environmental risks. Such hazards can cause personal injury and loss of life, severe damage to or destruction of property and equipment, and environmental damage, and may result in suspension of operations, disruption of service to customers, and the imposition of civil or criminal penalties. Houston Electric and Indiana Electric maintain property and casualty insurance but are not fully insured against all potential hazards incident to their businesses.

Houston Electric’s receivables are primarily concentrated in a small number of REPs, and any delay or default in payments of these receivables could adversely affect Houston Electric’s financial condition, results of operations and cash flows.

Houston Electric’s receivables from the distribution of electricity are collected from REPs that supply the electricity. As of December 31, 2023, Houston Electric provided electric delivery service to approximately 65 REPs. Adverse economic conditions, including, but not limited to, the impact of COVID-19, the February 2021 Winter Storm Event or other extreme weather (which may result in abnormal power prices), structural problems in the market served by ERCOT, mismanagement by the REPs, inflation or financial difficulties of one or more REPs, have and may in the future impair the ability of these REPs to pay for Houston Electric’s services or cause them to delay such payments. Houston Electric depends on these REPs to remit payments on a timely basis. Applicable PUCT regulations significantly limit the extent to which Houston Electric can apply normal commercial terms to otherwise seek credit protection from firms desiring to provide retail electric service in its service territory, and Houston Electric thus remains at risk for payments relating to services provided prior to any shift to another REP or provider of last resort. Houston Electric’s PUCT-approved tariff outlines the remedies available to Houston Electric in the event that a REP defaults on amounts owed. Among the remedies available to Houston Electric are seeking recourse against any cash deposit, letter of credit, or surety bond provided by the REP or implementing mutually agreeable terms with the REP. Another remedy is to require that customers be shifted to another REP or a provider of last resort. Houston Electric thus incurs risk for payments related to services provided prior to the shift to another REP or the provider of last resort. A significant portion of Houston Electric’s billed receivables from REPs are from affiliates of NRG and Vistra Energy Corp. Houston Electric’s aggregate billed receivables balance from REPs as of December 31, 2023 was $253 million. Approximately 39% and 20% of this amount was owed by affiliates of NRG and Vistra Energy Corp., respectively. Any delay or default in payment by REPs could adversely affect Houston Electric’s financial condition, results of operations and cash flows. If a REP was 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 regarding prior payments Houston Electric had received from such REP. For example, following the February 2021 Winter Storm Event, multiple REPs filed for bankruptcy. We are currently capturing the amounts owed by these REPs as a permitted regulatory asset for bad debt expenses, which will be subject to a reasonableness review by the PUCT when we seek recovery in our next base rate case. As of both December 31, 2022 and 2021, as authorized by the PUCT, CenterPoint Energy and Houston Electric recorded a regulatory asset of $8 million for bad debt expenses resulting from REPs’ default on their obligation to pay delivery charges to Houston Electric net of collateral. There is no guarantee that we will be able to recover any or all of the regulatory asset in our next base rate case. See “— Rate regulation of Registrants’ Electric ...”

Indiana Electric’s execution of its generation transition plan, including its IRP, is subject to various risks, including timely recovery of capital investments and increased costs and risks related to the timing and cost of development and/or construction of new generation facilities.

Indiana requires each electric utility to perform and submit an IRP to the IURC every three years, unless extended, that uses economic modeling to consider the costs and risks associated with available resource options to provide reliable electric service for the next 20-year period. Indiana Electric has used past IRPs and will continue to use future IRPs to evaluate its mix of generation resources. Indiana Electric engages with the communities it serves, its regulators and third-parties in developing its generation transition plan. Recent IRPs have demonstrated Indiana Electric can most cost effectively serve its customers by transitioning its generation fleet to a wider mix of resources, including renewables. For example, Indiana Electric’s 2019/2020 IRP identified a preferred portfolio that retires 730 MW of coal-fired generation facilities and replaces these resources with a mix of generating resources composed primarily of renewables, including solar, wind, and solar with storage, supported by dispatchable natural gas combustion turbines including a pipeline to serve such natural gas generation. Indiana Electric is continuing its plan to transition generation resources away from coal-fired generation to a more sustainable portfolio of resources, including renewables, and ultimately a goal to exit the coal plants that Indiana Electric operates by the end of 2027, as reflected in its most recent IRP submitted to the IURC in May 2023. While the IURC does not approve or reject Indiana Electric’s IRP, the IURC does comment on the IRP. Indiana Electric is required to obtain a CPCN prior to constructing or acquiring generating resources. Indiana Electric also obtains IURC approval of PPAs and DSM plans to ensure cost recovery.

Indiana Electric must manage several risks associated with its generation transition plan. The IURC may delay providing comments on Indiana Electric’s most recent IRP, requiring Indiana Electric to either wait for comments or proceed to
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implement its IRP without IURC comments. The IURC comments may raise concerns with Indiana Electric’s IRP that make it difficult to obtain approval of the generation transition plan if not addressed. There is no guarantee that the IURC will approve Indiana Electric’s requests to implement part of its generation transition. If Indiana Electric fails to receive IURC approvals necessary to acquire the projects or resources identified in its IRP, Indiana Electric may not be able to implement its generation transition plan in a timely manner or at all. If Indiana Electric is unable to implement its generation transition plan, it may have an adverse effect on CenterPoint Energy’s ability to execute on its net zero and carbon emission goals, its goal to exit the coal plants that Indiana Electric operates by the end of 2027, its growth strategy, achieve its financial goals, and otherwise impact results of operations and cash flows.

Even if a generation project is approved, risks associated with the development or construction of any new generation exist, including new legislation restricting or delaying new generation, moratorium legislation, the ability to procure resources needed to build at a reasonable cost, scarcity of resources and labor, ability to appropriately estimate costs of new generation, the effects of potential construction delays, project scope changes, and cost overruns and the ability to meet capacity requirements. For example, the developers of a 130 MW Pike County Solar project have informed Indiana Electric that, due to delays in the MISO interconnection queue and inflationary pressures, costs have exceeded the agreed upon levels in the BTA. We and the developers are actively evaluating possible cost impacts to the project, which may lead to a refile for approval of the project with the IURC and further delay the completion of the project. If Indiana Electric is not able to reach a mutually acceptable solution with the developers of the Pike County Solar project, Indiana Electric may seek to terminate the project. For additional information, see “— Disruptions to the global supply...” Furthermore, we have begun to acquire and/or develop additional solar and wind facilities as part of our capital plan. However, we have not yet entered into definitive agreements with developers for the acquisition and/or development of all of the additional projects, and we face significant competition with other bidders for a limited number of such generation facilities that developers plan to construct and for solar panels. For additional information, see “— Increases in the cost or reduction in supply ...” The number of available projects is further limited by the MISO interconnection queue due to potential interconnection costs that may render projects infeasible. As a result, suitable generation facility project candidates or resources necessary to construct such projects may not be available on terms and conditions we find acceptable, or the expected benefits of a completed facility may not be realized fully or at all, or may not be realized in the anticipated timeframe. If Indiana Electric was unable to meet its generation needs as a result of project delays or cancellations it would be required to buy the necessary capacity and electricity on the open market. Such open market purchases may result in increased costs and may have an adverse impact on our operations, financial condition, results of operations and cash flows. If we are unable to complete or acquire such generation facilities or resources, or if they do not perform as anticipated, our future growth, financial condition, results of operations and cash flows may be adversely affected.

Increases in the cost or reduction in supply of solar energy system components due to tariffs or trade restrictions imposed by the U.S. government may have an adverse effect on our business, financial condition and results of operations.

China is a major producer of solar panels and other solar products. Certain solar cells, modules, laminates and panels from China are subject to various antidumping and countervailing duty rates, depending on the exporter supplying the product, imposed by the U.S. government as a result of determinations the United States was materially injured as a result of such imports being sold at less than fair value and subsidized by the Chinese government. In March 2022, the DOC announced it would initiate an investigation into whether imports of solar cells and panels produced in Cambodia, Malaysia, Thailand and Vietnam are circumventing U.S. rules and laws, such as antidumping and countervailing duty rates, which impose a tariff on imports of solar cells and panels manufactured in China. On August 18, 2023, the DOC announced its final determination that five of the eight companies investigated were attempting to bypass U.S. duties by doing minor processing in Southeast Asian countries before shipment to the United States. In addition, in December 2021, President Biden signed into law the Uyghur Forced Labor Prevention Act, which bans goods from China’s Xinjiang region due to the use of forced labor. Continuing tensions between the United States and China may lead to restrictions in trade between the two countries or new legislation, tariffs or bans, any of which could further negatively impact the supply of solar panels. These or similar duties and legislation have and may in the future also put upward pressure on prices of these solar energy products, which may reduce our ability to acquire these items in a timely and cost-efficient manner. If we or the developers we are working with are unable to secure such solar energy products in a timely and cost-efficient manner, we may be forced to delay, downsize and/or cancel solar projects and we may not be able to procure the resources needed to fully execute on our ten-year capital plan or achieve our net zero emissions goals. We have experienced project delays due to developers of our projects being unable to acquire solar panels due to supply chain constraints. Additionally, delays or cancellations by developers of third-party solar power facilities expected to interconnect with CenterPoint Energy’s and Houston Electric’s system may have adverse impacts, such as delayed or reduced potential future revenues. We cannot predict what additional actions the U.S. government may adopt with respect to tariffs or other trade regulations in the future or what actions may be taken by other countries in retaliation for such measures. If the DOC imposes tariffs on solar panels as a result of its findings or other additional measures are imposed, our business, financial condition and results of operations may be adversely affected.

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The occurrence of extreme weather events, including winter storms and record hot temperatures, or other causes could lead to additional reforms to the Texas electric market, some measure of which, if implemented, could have an adverse impact on Houston Electric.

During and in the aftermath of the February 2021 Winter Storm Event, the Texas legislature revised applicable statutes and granted the PUCT and ERCOT additional regulatory authority, both oversight and enforcement, that focuses on ensuring ERCOT market participants, including power generation facilities and TDUs (like Houston Electric), have adopted sufficient winterization standards and protection. Houston Electric believes it is in compliance with the requirements applicable to it. If any additional protections are required in the future as a result of additional extreme weather events or other causes, complying with these new protections may increase the cost of electricity, which could adversely affect Houston Electric’s results of operations. Any potential decreases in customer usage due to higher electricity prices charged by REPs may not result in increased base rates charged by Houston Electric for its services until its next general base rate proceeding. For further information on Houston Electric’s regulatory proceedings, see “— Rate regulation of Registrants’ Electric...”

In addition, the PUCT and ERCOT continue to review the appropriate reliability standard and market design for the Texas electric market. There are uncertainties whether any further changes will result from these discussions or other efforts. If there are changes to how the Texas electric market is structured or regulated, such changes could have an adverse impact on Houston Electric’s business, financial condition and results of operations. See Note 7 to the consolidated financial statements for further information.

Houston Electric’s use of TEEEF is subject to various risks, including failure to obtain and deploy sufficient TEEEF resources, potential performance issues and allegations about Houston Electric’s deployment of the resources (including the planning, execution, and effectiveness of the same), regulatory and environmental requirements, and timely recovery of capital.

Following the February 2021 Winter Storm Event, the Texas legislature passed a law, effective September 1, 2021, that allows TDUs, such as Houston Electric, to lease and temporarily operate back-up generation resources during widespread power outages where ERCOT has ordered a TDU to Load Shed or the TDU’s distribution facilities are not being fully served by the bulk power system under normal operations. In response to this legislation, Houston Electric entered into two leases for TEEEF (mobile generation). In 2023, the Texas legislature amended the law to allow wider use of TEEEF.

If Houston Electric is unable to deploy a sufficient number of TEEEF resources in time to respond to a particular event; if TEEEF resources fail to perform as intended; if Houston Electric is otherwise unable to provide back-up generation resources and restore power as intended; or if the use of TEEEF resources or their failure to perform causes or is alleged to cause any personal injury, property damage, or other damage or loss due to allegations Houston Electric failed to deploy such units reasonably or effectively and failed to respond to particular power outages, Houston Electric could be subject to claims, demands, litigation, liability, regulatory scrutiny, and loss of reputation. While Houston Electric has insurance coverage and indemnity rights for its use of TEEEF resources, if its insurers or indemnitors fail to meet their indemnity obligations, Houston Electric could be liable for personal injury, property damage, or other damage or loss. As noted above, the legislation prescribes specific and limited use for TEEEF, and Houston Electric’s TEEEF have limited generation capacity, such that in future events customers could still be without power despite deployment of TEEEF resources.

Further, TEEEF resources are subject to various environmental regulations and permitting requirements, which could have an impact on Houston Electric’s ability to use these units. If Houston Electric is not in compliance with any environmental regulation or permitting requirement, Houston Electric could be subject to further potential liability. The use of TEEEF is also subject to various requirements, and failure to comply with them could subject Houston Electric to additional liability as well as challenges to its use of TEEEF in general. In April 2023, the PUCT approved revenue recovery of $39 million of TEEEF costs incurred in 2021, and in October 2023, an agreement with intervenors was reached with respect to Houston Electric’s second TEEEF filing for revenue recovery of $153 million ($114 million incremental to the prior filing) of TEEEF costs incurred through December 31, 2022, and the agreement was approved by PUCT in February 2024. Despite the recovery of these TEEEF costs in the past, there can be no assurances that Houston Electric will be able to recover future TEEEF costs.If Houston Electric is unable to recover any or all of its TEEEF costs our financial condition, results of operations and cash flows may be adversely affected. For further information, see “— Rate regulation of Registrants’ Electric...”, “— Our Consolidatedinsurance coverage may not...” and “— We are subject to operational...”
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The impact of wildfires could negatively affect Houston Electric’s and Indiana Electric’s financial condition, results of operations and cash flows.

Wildfires have the potential to negatively affect communities within Houston Electric’s and Indiana Electric’s service territories and the surrounding areas, as well as Houston Electric’s and Indiana Electric’s vast network of electric transmission and distribution lines and facilities. The possibility of wildfires and the risk of damage to our network and facilities resulting therefrom may be exacerbated by severe weather events and the effects of climate change. For more information regarding climate related risks, see “ — Climate change could adversely impact ...” The continued expansion of the wildland-urban interface has also increased wildfire risk to communities in our service territories. While we proactively take steps to mitigate wildfire risk in the areas of our electrical assets, wildfire risk is always present. Houston Electric or Indiana Electric could be held liable for damages incurred as a result of wildfires or incur reputational harm if it was determined that they were caused by or enhanced due to any fault of Houston Electric or Indiana Electric. Wildfires could also lead to significant financial distress and further increased costs for wildfire insurance or lack of availability thereof. Furthermore, any damage caused to our assets, loss of service to our customers, or liability imposed as a result of wildfires could negatively impact Houston Electric’s or Indiana Electric’s financial condition, results of operations, and cash flows.

Natural Gas (CenterPoint Energy and CERC)

Access to natural gas supplies and pipeline transmission and storage capacity are essential components of reliable service for Natural Gas’ customers.

Natural Gas depends on third-party service providers to maintain an adequate supply of natural gas and for available storage and intrastate and interstate pipeline capacity to satisfy its customers’ needs, all of which are critical to system reliability. Substantially all of Natural Gas’ natural gas supply is purchased on intrastate and interstate pipelines. If Natural Gas is unable to secure an independent natural gas supply of its own or if third-party service providers fail to timely deliver natural gas to meet Natural Gas’ requirements, the resulting decrease in natural gas supply in Natural Gas’ service territories could have an adverse effect on its financial condition, results of operations and cash flows. Additionally, a significant disruption, whether through reduced intrastate and interstate pipeline transmission or storage capacity or other events affecting natural gas supply, including, but not limited to, operational failures, hurricanes, tornadoes, floods, severe winter weather conditions, wildfires, acts of terrorism, human error or cyberattacks or changes in legislative or regulatory requirements, could also adversely affect Natural Gas’ businesses. Further, to the extent that Natural Gas’ natural gas requirements cannot be met through access to or continued use of existing natural gas infrastructure or if additional infrastructure, including onshore and offshore exploration and production facilities, gathering and processing systems and pipeline and storage capacity is not constructed at a rate that satisfies demand, then Natural Gas’ operations could be negatively affected.

Natural Gas is subject to fluctuations in natural gas prices, which could affect the ability of its suppliers and customers to meet their obligations or may impact its operations, which could adversely affect CERC’s financial condition, results of operations and cash flows.

Natural Gas is subject to risk associated with changes in the price of natural gas. Significant increases in natural gas prices, such as those experienced during the February 2021 Winter Storm Event, might affect Natural Gas’ ability to collect balances due from customers and could create the potential for uncollectible accounts expense to exceed the recoverable levels built into tariff rates. In addition, a sustained period of high natural gas prices could (i) decrease demand for natural gas in the areas in which Natural Gas operates, thereby resulting in decreased sales and revenues and (ii) increase the risk that Natural Gas’ suppliers or customers fail or are unable to meet their obligations. An increase in natural gas prices would also increase working capital requirements by increasing the investment that must be made to maintain natural gas inventory levels.

Natural Gas must compete with alternate energy sources, which could result in less natural gas delivered and have an adverse impact on CenterPoint Energy’s and CERC’s financial condition, results of operations and cash flows.

Natural Gas competes primarily with alternate energy sources such as electricity and other fuel sources. In some areas, intrastate pipelines, other natural gas distributors and natural gas marketers also compete directly with Natural Gas for natural gas sales to end users. In addition, as a result of federal regulatory changes affecting interstate pipelines, natural gas marketers operating on these pipelines may be able to bypass Natural Gas’ facilities and market, sell and/or transport natural gas directly to commercial and industrial customers. Any reduction in the amount of natural gas delivered by Natural Gas as a result of competition with alternate energy sources may have an adverse impact on CenterPoint Energy and CERC’s financial condition, results of operations and cash flows.
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Risk Factors Affecting Regulatory, Environmental and Legal Risks

Rate regulation of Registrants’ Electric and Natural Gas businesses may delay or deny their ability to earn an expected return and fully and timely recover their costs.

The Registrants’ Electric and Natural Gas businesses are regulated by certain municipalities and state commissions. Their rates are set in comprehensive base rate proceedings (i.e., general rate cases) based on an analysis of their invested capital, their expenses and other factors in a designated test year (often either fully or partially historic), subject to periodic review and adjustments. Each of these rate proceedings is subject to third-party intervention and appeal, and the timing of a general base rate proceeding may be out of the Registrants’ control. Indiana Electric and CERC each filed rate cases during 2023. Houston Electric and CERC, with respect to its Ohio gas territory, each plan to file a rate case during 2024. The Registrants can make no assurance that their or their subsidiaries respective base rate proceedings will result in requested or favorable adjustments to their rates, in full and timely cost recovery or approval of other requested items, including, among other things, capital structure and ROE. Moreover, these base rate proceedings have caused in certain instances, and in the future could cause, the Registrants’ Electric and/or Natural Gas businesses to recover their investments below their requested levels, below the national average return for utilities or below recently approved return levels for other utilities in their respective jurisdictions. For instance, in the 2019 Houston Electric general rate case, Houston Electric filed a base rate case seeking approval for revenue increases of approximately $194 million and a 10.4% ROE, but after entering into a Stipulation and Settlement Agreement filed with the PUCT, Houston Electric received an overall revenue requirement increase of approximately $13 million and a 9.4% ROE. To the extent the regulatory process does not allow the Registrants to make a full and timely recovery of appropriate costs, their financial condition, results of operations and cash flows could be adversely affected. Further, the Registrants or their subsidiaries might be required to implement additional measures, such as the adoption of ring-fencing measures by Houston Electric in connection with its 2019 rate case proceeding. Such additional measures may adversely impact the Registrants’ businesses and could have an adverse effect on their financial condition, results of operations and cash flows.

The rates that Registrants’ Electric and Natural Gas businesses are allowed to charge may not match their costs at any given time, a situation referred to as “regulatory lag.” Regulatory lag has been and may be exaggerated in the future under certain circumstances, such as increasing inflation rates like those experienced in 2022 and continuing into 2023. For example, the MPUC ordered extraordinary gas costs incurred in the February 2021 Winter Storm Event be recovered over a 63-month period from 2022 — 2027 and CERC forego recovery of the associated carrying costs. Though several interim rate adjustment mechanisms have been approved by jurisdictional regulatory authorities and implemented by the Registrants and their subsidiaries to reduce the effects of regulatory lag (for example, CSIA, DCRF, DRR, DSMA, GRIP, RCRA, RRA, RSP, TCOS and TDSIC), such adjustment mechanisms are subject to the applicable regulatory body’s approval, which we cannot assure would be approved, and are subject to certain limitations that may reduce or otherwise impede the Registrants’ or their subsidiaries ability to adjust its rates or result in rates below those requested. Therefore, the Registrants can make no assurance filings for such mechanisms will result in favorable adjustments to rates or in full cost recovery. Further, from time to time, the Registrants’ regulators approve the issuance of securitization bonds in order to recover certain costs, including costs incurred as a result of severe weather or to recover stranded asset costs. The issuance of these securitization bonds may be delayed. If the issuance of securitization bonds is delayed, we may not be able to recover our costs in a timely manner, which could have an adverse effect on CenterPoint Energy’s, CERC’s, and Houston Electric’s financial condition, results of operations and cash flows.

Inherent in the regulatory process is some level of risk jurisdictional regulatory authorities may challenge the reasonableness or prudency of operating expenses incurred or capital investments made by the Registrants or their subsidiaries and deny the full recovery of their cost of service in rates. From time to time, these reviews and investigations have caused in certain instances, and in the future could cause, the Registrants’ to recover their costs or investments below their requested levels. For example, in October 2022, the MPUC issued a written order disallowing recovery of approximately $36 million of the $409 million originally requested by CERC in connection with its recovery of costs incurred as a result of the February 2021 Winter Storm Event. Notwithstanding the application of such rate adjustment mechanisms, the regulatory process by which rates are determined is subject to change as a result of legislative processes or rulemakings, as the case may be, and may not always be available or result in rates that will produce recovery of the Registrants’ or their subsidiaries’ costs or enable them to earn their authorized return. Changes to the rate case or interim adjustment mechanisms could result in an increase in regulatory lag or otherwise impact the Registrants’ ability to recover their costs in a timely manner. Additionally, decisions from regulators are typically subject to appeal, and any such appeal could further exacerbate regulatory lag and lead to additional uncertainty associated with rate case proceedings. To the extent the regulatory process does not allow the Registrants to make a full and timely recovery of appropriate costs, their financial condition, results of operations and cash flows could be adversely affected. For further information on rate case proceedings and interim rate adjustment mechanisms, see
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“Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Regulatory Matters” in Item 7 of Part II of this report.


We face risks related to project siting, financing, construction, permitting, governmental approvals, public opposition, and the negotiation of project development agreements that may impede our development and operating activities.

Houston Electric, Indiana Electric and CERC own, develop, construct, manage and operate electric generation, transmission and distribution facilities or natural gas distribution facilities, as applicable. A key component of our growth is our ability to construct and operate these facilities. As part of these operations, we must periodically apply for licenses and permits from various local, state, federal and other regulatory authorities and abide by their respective conditions. We have previously experienced delays in receiving approval with regards to certain permits and licenses, and have had investigations and enforcement actions with regards to certain of our projects, which have caused delays to our projects in the past. Should we in the future be unsuccessful in obtaining necessary licenses or permits on acceptable terms or resolving third-party challenges to such licenses or permits, should there be a delay in obtaining or renewing necessary licenses or permits, or should regulatory authorities initiate any associated investigations or enforcement actions or impose related penalties or disallowances, our future net income and cash flows could be reduced and our financial condition could be impacted. Any failure to negotiate successful project development agreements for new facilities with third parties could also have adverse effects. Additionally, our projects have faced and may in the future face opposition from individuals, community organizations, environmental and other activist groups, and other public-interest entities.

We are subject to operational and financial risks and liabilities arising from environmental laws and regulations, including regulation of CCR,climate change legislation and certain local initiatives that seek to limit fossil fuel usage.

Our operations are subject to stringent and complex laws and regulations pertaining to the environment. As an owner or operator of natural gas pipelines, distribution systems and storage, electric generating facilities and electric transmission and distribution systems, and the facilities that support these systems, we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, including among others, restricting the use of fossil fuels through future climate legislation or regulation, restricting the use of natural gas-fired appliances in new homes, limiting airborne emissions from generating facilities, restricting the way we manage wastes, including wastewater discharges, air emissions and CCR removal, and requiring remedial action or monitoring to mitigate environmental actions caused by our operations or attributable to former operations. We may need to spend substantial amounts and devote other resources from time to time to comply with these requirements. Further, in the course of operations we have released, and may in the future inadvertently release, various contaminants. Any such releases could have a significant impact on the environment and result in significant fines. Failure to comply with applicable environmental laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, which we have been subject to from time to time, revocation of permits, the imposition of remedial actions, and the issuance of orders enjoining future operations. Certain environmental statutes impose strict joint and several liability for costs required to clean, restore and monitor sites where hazardous substances have been stored, disposed or released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other waste products into the environment.

Regulatory agencies have also adopted, and from time to time consider adopting, new legislation and/or modifying existing laws and regulations to reduce GHGs. There continues to be a wide-ranging policy and regulatory debate, both nationally and internationally, regarding the possible means for their regulation. The trend in environmental regulation has been to place more restrictions and limitations on activities that may impact the environment. On April 22, 2021, President Biden announced new goals of 50% reduction of economy-wide GHG emissions and 100% carbon-free electricity by 2035, which formed the basis of the United States’ commitments announced in Glasgow, Scotland. These renewed climate commitments coming out of the 2021 United Nations Climate Change Conference held in Glasgow and President Biden’s executive orders have resulted in the development of additional regulations and changes to existing regulations. For example, in May 2023, the EPA proposed regulations setting new GHG emission reduction targets for coal and gas-fired electric generating units that could potentially require additional operating costs or operating restrictions related to operation of Indiana Electric’s natural-gas fired units. The administration is expected to finalize additional GHG regulations and mandated financial, emissions and other disclosures. As a distributor and transporter of natural gas and electricity, and a generator of electricity in Indiana, the Registrants’ revenues, operating costs and capital requirements could be adversely affected as a result of any regulatory action that would require installation of new control technologies or a modification of its operations or that would have the effect of reducing the consumption of natural gas or electricity or prevent the use of certain fuel types. Also, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be greater than the amounts we currently anticipate, which could adversely affect our financial condition, results of operations and
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cash flows. Likewise, incentives to conserve energy or use energy sources other than natural gas could result in a decrease in demand for our services. For further discussion, see “Business—Environmental Matters” in Item 1 and “ —Natural Gas must compete with…”

Evolving investor sentiment related to the use of fossil fuels and initiatives to restrict continued production of fossil fuels may have substantial impacts on CenterPoint Energy’s and CERC’s electric generation and natural gas businesses. For example, because Indiana Electric’s current generating units substantially rely on coal for their operations, certain financial institutions may choose not to participate in CenterPoint Energy’s financing arrangements until future coal generation closures satisfy their thresholds for investments. Further, some investors choose to not invest in CenterPoint Energy due to CenterPoint Energy’s and CERC’s use of fossil fuels. Also, certain cities in CenterPoint Energy’s and CERC’s Natural Gas operational footprint have discussed the adoption of initiatives to prohibit the construction of new natural gas facilities that would provide service and focus on electrification. For example, Minneapolis has adopted carbon emission reduction goals in an effort to decrease reliance on fossil natural gas. Certain state and local governments have also passed, or are considering, legislation banning the use of natural gas-fired appliances in new homes, which could affect consumer use of natural gas. Should such bans be enacted within Natural Gas’ operational footprint, they could adversely affect consumer demand for natural gas. Any such initiatives and legislation could adversely affect CenterPoint Energy’s and CERC’s results of operations. Further, investors, lenders, regulators and other stakeholders are focusing on issues related to environmental justice, which may result in increased scrutiny of our applicable regulatory processes and additional costs of compliance or may adversely affect our reputation. This focus on environmental justice matters at the federal and state levels may also provide communities opposed to our operations with greater opportunities to challenge or delay our projects. Opposition to our projects or successful challenges or appeals to permits issued for our projects could result in cancellation of such projects and the loss of investments we have made with respect thereto.

CenterPoint Energy is subject to operational and financial risks and liabilities associated with the implementation of and efforts to achieve its carbon emissions reduction goals.

In September 2021, CenterPoint Energy announced its net zero emission goals for Scope 1 and certain Scope 2 emissions by 2035 and a 20-30% reduction in certain Scope 3 emissions by 2035 as compared to 2021 levels. CenterPoint Energy’s analysis and plan for execution requires it to make a number of assumptions. These goals and underlying assumptions involve risks and uncertainties and are not guarantees. Should one or more of CenterPoint Energy’s underlying assumptions prove incorrect, its actual results and ability to achieve net zero emissions by 2035 could differ materially from its expectations. Certain of the assumptions that could impact CenterPoint Energy’s ability to meet its net zero emissions goals include, but are not limited to: emission levels, service territory size and capacity needs remaining in line with expectations; regulatory approvals related to Indiana Electric’s generation transition plan; customer demand for carbon free energy; impacts of future environmental regulations or legislation; impacts of future carbon pricing regulation or legislation, including a future carbon tax; price, availability and regulation of carbon offsets; price of fuel, such as natural gas; cost of energy generation technologies, such as wind and solar, natural gas and storage solutions; adoption of alternative energy by the public, including adoption of electric vehicles; rate of technology innovation with regards to alternative energy resources; CenterPoint Energy’s ability to implement its modernization plans for its pipelines and facilities; the ability to complete and timely implement generation alternatives, such as solar and wind generation, to Indiana Electric’s coal generation and retirement dates of Indiana Electric’s coal facilities by 2035; the ability to construct and/or permit new natural gas pipelines; the ability to procure resources needed to build at a reasonable cost, the lack of or scarcity of resources and labor, any project cancellations, construction delays or overruns and the ability to appropriately estimate costs of new generation; impact of any supply chain disruptions; changes in applicable standards or methodologies; and enhancement of energy efficiencies. Our businesses may face increased scrutiny from investors and other stakeholders related to our sustainability activities, including the goals, targets, and objectives we announce, our methodologies and timelines for pursuing them, and related disclosures. If our sustainability practices do not align with investor or other stakeholder expectations and standards, which continue to evolve, our reputation, our ability to attract or retain employees, and our attractiveness as an investment or business partner could be negatively affected. Similarly, our failure or perceived failure to pursue or fulfill our sustainability-focused goals, targets, and objectives, to comply with ethical, environmental, or other standards, regulations, or expectations, or to satisfy various reporting standards with respect to these matters, within the timelines we announce, or at all, could adversely affect our business or reputation, as well as expose us to government enforcement actions and private litigation.

Developing and implementing plans for compliance with voluntary climate commitments can lead to additional capital, personnel and operation and maintenance expenditures and could significantly affect the economic position of existing facilities and proposed projects. To the extent that we believe any of these costs are recoverable in rates, cost recovery could be resisted by our regulators and our regulators might attempt to deny or defer timely recovery of these costs. Moreover, we cannot predict
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the ultimate impact of achieving our emissions reduction goals, or the various implementation aspects, on our system reliability or our financial condition and results of operations.

Houston Electric and Indiana Electric, as a member of ERCOT and MISO, respectively, could be subject to higher costs for system improvements, as well as fines or other sanctions as a result of FERC mandatory reliability standards.

Houston Electric and Indiana Electric are members of ERCOT and MISO, respectively, which serve the electric transmission needs of their applicable regions. As a result of their respective participation in ERCOT and MISO, Houston Electric and Indiana Electric do not have operational control over their transmission facilities and are subject to certain costs for improvements to these regional electric transmission systems. In addition, FERC has jurisdiction with respect to ensuring the reliability of electric transmission service, including transmission facilities owned by Houston Electric and other utilities within ERCOT and Indiana Electric and other utilities within MISO, respectively. FERC has designated NERC as the ERO to promulgate standards, under FERC oversight, for all owners, operators and users of the bulk power system. FERC has approved the delegation by NERC of authority for reliability in ERCOT to the Texas RE, a Texas non-profit corporation, and for reliability in the portion of MISO that includes Indiana Electric to ReliabilityFirst Corporation, a Delaware non-profit corporation. Compliance with mandatory reliability standards may subject Houston Electric and Indiana Electric to higher operating costs and may result in increased capital expenditures, which may not be fully recoverable in rates. While Houston Electric and Indiana Electric have received minor fines in the past for noncompliance, if Houston Electric or Indiana Electric were to be found to be in noncompliance with applicable mandatory reliability standards again, they would be subject to sanctions, including potential monetary penalties, which could range as high as over a million dollars per violation per day, and non-monetary penalties, such as having to file a mitigation plan to prevent recurrence of a similar violation and having certain milestones in such plan tracked.

We are involved in numerous legal proceedings, the outcomes of which are uncertain, and resolutions adverse to us could negatively affect our financial results.

The Registrants are subject to numerous legal proceedings, including lawsuits and environmental matters in addition to regulatory proceedings, the most significant of which are summarized in Note 15 to the consolidated financial statements. Litigation is subject to many uncertainties; recent trends have shown jury verdicts, settlements and other liability have been significantly increasing; and the Registrants cannot predict the outcome of all matters with assurance. Additionally, under some circumstances, the Registrants could potentially have claims filed against them or incur liabilities associated with assets and businesses no longer owned by them as a holding company with no operationsresult of sales, divestitures or operating assetsother transfers to third parties who may be unable to fulfill their indemnity obligations to the Registrants. Final resolution of these matters, or any potential future claims or liabilities, may require additional expenditures over an extended period of time that may be in excess of established insurance or reserves and may have an adverse effect on the Registrants’ financial results.

Our businesses may be adversely affected by the intentional misconduct of our own.employees.

We are committed to living our core values of safety, integrity, accountability, initiative and respect and complying with all applicable laws and regulations. Despite that commitment and efforts to prevent misconduct, it is possible for employees to engage in intentional misconduct, fail to uphold our core values, and violate laws and regulations for individual gain through contract or procurement fraud, misappropriation, bribery or corruption, fraudulent related-party transactions and serious breaches of our Ethics and Compliance Code and other policies. If such intentional misconduct by employees should occur, it could result in substantial liability, higher costs, increased regulatory scrutiny and negative public perceptions, any of which could have an adverse effect on our financial condition, results of operations and cash flows. From time to time, including as part of our Ethics and Compliance program’s efforts to detect misconduct, we become aware of and expect to continue to become aware of instances of employee misconduct, which we investigate, remediate and disclose as appropriate and proportionate to the incident.

Risk Factors Affecting Financial, Economic and Market Risks

Disruptions to the global supply chain may lead to higher prices for goods and services and impact our operations, which could have an adverse impact on our ability to execute our capital plan and on our financial condition, results of operations and cash flows.

The global supply chain has experienced disruptions due to a multitude of factors, such as the COVID-19 pandemic, labor shortages, resource availability, long lead time, delivery delays, inflation, severe weather events and disruptions to internal or international shipping, including as a result of armed conflicts, and these disruptions have adversely impacted the utility industry. We, as well as other companies in our industry, have experienced supply chain disruptions, as well as increased prices,
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and we may continue to experience this in the future. Examples of materials necessary for the transmission and distribution of power we and our industry have experienced difficulties in procuring include transformers, wires, cables, meters, poles and solar panels. If the supply chain disruption persists or worsens, we may experience difficulties in procuring these resources and others necessary to operate our businesses in the future. As a result, we dependmay not be able to procure the resources, including labor, needed to timely perform storm restoration activities, fully execute on our ten-year capital plan and/or achieve our net zero emission and carbon emissions reduction goals. Moreover, high inflation and persistent high interest rates continue to be an area of economic concern and has contributed to the increased prices for materials and services that have been experienced by us and other companies in our industry. Even if we are able to procure the necessary resources, we might not be able to do so at a reasonable cost or in a timely manner which could result in project cancellations or scope changes, delays, cost overruns and under-recovery of costs. If we are unable to fully execute on capital plans as a result of supply chain disruptions, our financial condition, results of operations and cash flows may be adversely affected.

CenterPoint Energy is a holding company that derives all of its operating income from, and holds substantially all of its assets through, its subsidiaries. As a result, CenterPoint Energy depends on the performance of and distributions from ourits subsidiaries and from Enable to meet ourits payment obligations and to pay dividends on ourits common stock, and provisions of applicable law or contractual restrictions could limit the amount of those distributions.


We deriveCenterPoint Energy derives all of ourits operating income from, and holdholds substantially all of ourits assets through, ourits subsidiaries. Similarly, as a result of the Restructuring, CERC derives a significant portion of its operating income from and holds a significant portion of its assets through its subsidiaries, including our interests in Enable.Indiana Gas and VEDO. As a result, weCenterPoint Energy and to a lesser extent, CERC, depend on the performance of and distributions from ourtheir respective subsidiaries and Enable to meet ourtheir respective payment obligations and to pay dividends on ourtheir respective common stock. In general, ourCenterPoint Energy’s and CERC’s subsidiaries are separate and distinct legal entities and have no obligation to provide usthem with funds for ourtheir respective payment obligations, whether by dividends, distributions, loans or otherwise. In addition, provisions of applicable law, such as those limiting the legal sources of dividends, limit ourCenterPoint Energy’s and CERC’s respective subsidiaries’ and Enable’s ability to make payments or other distributions to us,CenterPoint Energy or CERC, and ourtheir respective subsidiaries or Enable could agree to contractual restrictions on their ability to make payments or other distributions. ForFurther, as part of Houston Electric’s 2019 base rate case, Houston Electric agreed to certain “ring-fencing” measures to increase its financial separateness from CenterPoint Energy. Houston Electric is expected to file a discussionbase rate proceeding in 2024. In this proceeding, Houston Electric may be requested to institute further ring-fencing measures or further ring-fencing measures could be imposed on Houston Electric in the future through legislation or PUCT rules or orders. While current ring-fencing measures have not impacted Houston Electric’s ability to pay dividends to CenterPoint Energy, the imposition of risks that may impact the amount of cash distributions weany additional measures impacting CenterPoint Energy’s ability to receive with respect to our interests in Enable, please read “ — Additional Risk Factors Affecting Our Interests in Enable Midstream Partners, LP — Ourdividends from Houston Electric could adversely affect CenterPoint Energy’s cash flows, will becredit quality, financial condition and results of operations. Any such adverse effect on CenterPoint Energy could also adversely impacted if we receive lessaffect Houston Electric’s and/or CERC’s cash distributions from Enable than we currently expect”flows, credit quality, financial condition and “ — Other Risk Factors Affecting Our Businesses or Our Interests in Enable Midstream Partners, LP — Our or Enable’s potential business strategies and strategic initiatives, including merger and acquisition activities and the dispositionresults of assets or businesses,operations as CenterPoint Energy may not be completed able to financially support Houston Electric and/or perform as expected.”CERC if and when necessary.

OurCenterPoint Energy’s right to receive any assets of any subsidiary, and therefore the right of ourits creditors to participate in those assets, will be effectivelyare structurally subordinated to the claims of that subsidiary’s creditors, including trade creditors. In addition, even if weCenterPoint Energy were a creditor of any subsidiary, ourits rights as a creditor would likely be effectively subordinated to any security interest in the assets of that subsidiary and any senior indebtedness of the subsidiary senior to that held by us.subsidiary.


If we are unable to arrange future financings on acceptable terms, our ability to finance our capital expenditures orrefinance existingoutstanding indebtedness could be limited.


Our businesses are capital intensive. Weintensive, and we rely on various sources to finance our capital expenditures. For example, we depend on (i) on long-term debt, to finance a portion of our capital expenditures and refinance our existing debt, (ii) on short-term borrowings through our revolving credit facilities and, for CenterPoint Energy and CERC, commercial paper programs and (iii) on distributions from our interests in Enable to satisfy liquidity needs to the extent not satisfiedif market conditions permit, issuances of additional shares of common stock or shares of preferred stock by cash flow from our business operations; weCenterPoint Energy. We may also dependuse such sources to refinance any outstanding indebtedness as it matures. Additionally, from time to time, our operating subsidiaries, including Houston Electric and CERC, may rely on the net proceedsintercompany borrowings from a potential sale of common units we own in Enable.CenterPoint Energy that may be sourced from CenterPoint Energy’s external financings. As of December 31, 2017, we2023, CenterPoint Energy had $8.8$19 billion of outstanding indebtedness on a consolidated basis, which includes $1.9 billion$502 million of non-recourse Securitization Bonds. AsFor information on outstanding indebtedness of December 31, 2017, approximately $50 million principal amount of this debt is requiredCenterPoint Energy, Houston Electric and CERC as well as future maturities, see Note 13 to be paid through 2020. This amount excludes principal repayments of approximately $1.1 billion on Securitization Bonds, for which dedicated revenue streams exist.the consolidated financial statements. Our future financing activities may be significantly affected by, among other things:


•general economic and capital market conditions;conditions, including inflation;

•credit availability from financial institutions and other lenders;

volatility or fluctuations in distributions from Enable’s units or volatility in Enable’s unit price;

•investor confidence in us and the markets in which we operate;

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•the future performance of our businesses;
•maintenance of acceptable credit ratings;

•actions from the Federal Reserve, including changes in interest rates and unanticipated actions;
•market expectations regarding our future earnings and cash flows;

•investor willingness to invest in companies associated with fossil fuels;
•our ability to access capital markets on reasonable terms;

•timing of future securitizations by jurisdictions in which we operate; and


our exposure to GenOn (formerly known as RRI Energy, Inc., Reliant Energy and RRI), a wholly-owned subsidiary of NRG and currently the subject of bankruptcy proceedings, in connection with certain indemnification obligations;

incremental collateral that may be required due to regulation of derivatives; and

•provisions of relevant tax and securities laws.


As of December 31, 2017, Houston Electric had approximately $2.9 billion aggregate principal amount of general mortgage bonds outstanding under the General Mortgage, including approximately $118 million held in trust to secure pollution control bonds for which we are obligated. Additionally, as of December 31, 2017, Houston Electric had approximately $102 million aggregate principal amount of first mortgage bonds outstanding under the Mortgage. Houston Electric may issue additional general mortgage bonds on the basis of retired bonds, 70% of property additions or cash deposited with the trustee. Approximately $4.2 billion of additional first mortgage bonds and general mortgage bonds in the aggregate could be issued on the basis of retired bonds and 70% of property additions as of December 31, 2017. However, Houston Electric has contractually agreed that it will not issue additional first mortgage bonds, subject to certain exceptions.

OurThe Registrants’ current credit ratings and any changes in credit ratings in 2023 and to date in 2024 are discussed in “Management’s Discussion and Analysis of Financial Condition and Results of Operations -— Liquidity and Capital Resources — Other Matters — Impact on Liquidity of a Downgrade in Credit Ratings” in Item 7 of Part II of this report. These credit ratings may not remain in effect for any given period of time and one or more of these ratings may be loweredreduced or withdrawn entirely by a rating agency. WeThe Registrants note that these credit ratings are not recommendations to buy, sell or hold ourtheir securities. Each rating should be evaluated independently of any other rating. Any future reduction or withdrawal of one or more of ourthe Registrants’ credit ratings could have a materialan adverse impact on ourtheir ability to access capital on acceptable terms.

An impairment of goodwill, long-lived assets, including intangible assets, and equity and cost method investments could reduce our earnings.

Goodwill is recorded when the purchase price of a business exceeds the fair market value of the tangible and separately measurable intangible net assets. Accounting principles generally accepted in the United States of America require us to test goodwill for impairment on an annual basis or when events or circumstances occur indicating that goodwill might be impaired. Long-lived assets, including intangible assets with finite useful lives, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable.

For investments we account for under the equity or cost method, the impairment test considers whether the fair value of such investment as a whole, not the underlying net assets, has declined and whether that decline is other than temporary. For example, if Enable’s unit price, distributions or earnings were to decline, and that decline is deemed to be other than temporary, we could determine that we are unable to recover the carrying value of our equity investment in Enable. Considerable judgment is used in determining if an impairment loss is other than temporary and the amount of any impairment. A sustained low Enable common unit price could result in our recording impairment charges in the future.

Should our annual impairment test or another periodic impairment test, as described above, indicate the fair value of our assets is less than the carrying value, we would be required to take a non-cash charge to earnings with a correlative effect on equity and balance sheet leverage as measured by debt to total capitalization. A non-cash impairment charge could materially adversely impact our results of operations and financial condition.

Increased utilization due to changing demographics, poor investment performance of the pension plan and other factors adversely affecting the calculation of pension liabilities could unfavorably impact our results of operations, liquidity and financial position.

We maintain a qualified defined benefit pension plan covering substantially all employees. Our costs of providing this plan are dependent upon a number of factors including the investment returns on plan assets, the level of interest rates used to calculate the funded status of the plan, our contributions to the plan and government regulations with respect to funding requirements and the calculation of plan liabilities. Funding requirements may increase and we may be required to make unplanned contributions in the event of a decline in the market value of plan assets, a decline in the interest rates used to calculate the present value of future plan obligations or government regulations that increase minimum funding requirements or the pension liability. In addition to affecting our funding requirements, each of these factors could adversely affect our results of operations, liquidity and financial position.


The costs of providing health care benefits to our employees and retirees may increase substantially and adversely affect our results of operations and financial condition.

We provide health care benefits to eligible employees and retirees through self-insured plans. In recent years, the costs of providing these benefits have risen due to increasing health care costs and increased levels of large individual health care claims and overall health care claims, and we anticipate that such costs will continue to rise. Further, the effects of health care reform or any future legislative changes could also materially affect our health care benefit programs and costs. Any potential changes and resulting cost impacts, which are likely to be passed on to us, cannot be determined with certainty at this time. Our costs of providing these benefits could also increase materially in the future should there be a material reduction in the amount of the recovery of these costs through our rates or should significant delays develop in the timing of the recovery of such costs, which could adversely affect our results of operations and liquidity.

The use of derivative contracts in the normal course of business by us, our subsidiaries or Enable could result in financial losses that could negatively impact our results of operations and those of our subsidiaries or Enable.

We and our subsidiaries use derivative instruments, such as swaps, options, futures and forwards, to manage our commodity, weather and financial market risks. Enable may also use such instruments from time to time to manage its commodity and financial market risks. We, including our subsidiaries, or Enable could recognize financial losses as a result of volatility in the market values or ineffectiveness of these contracts or should a counterparty fail to perform. Additionally, in the absence of actively quoted market prices and pricing information from external sources, the valuation of these financial instruments can involve management’s judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts.

If we redeem the ZENS prior to their maturity in 2029, our ultimate tax liability and redemption payments would result in significant cash payments, which would adversely impact our cash flows. Similarly, a significant amount of exchanges of ZENS by ZENS holders could adversely impact our cash flows.

We have approximately $828 million principal amount of ZENS outstanding as of December 31, 2017. We own shares of TW Securities equal to approximately 100% of the reference shares used to calculate our obligation to the holders of the ZENS. We may redeem all of the ZENS at any time at a redemption amount per ZENS equal to the higher of the contingent principal amount per ZENS ($505 million in the aggregate, or $35.54 per ZENS, as of December 31, 2017) or the sum of the current market value of the reference shares attributable to one ZENS at the time of redemption. In the event we redeem the ZENS, in addition to the redemption amount, we would be required to pay deferred taxes related to the ZENS. Our ultimate tax liability related to the ZENS continues to increase by the amount of the tax benefit realized each year. If the ZENS had been redeemed on December 31, 2017, deferred taxes of approximately $521 million would have been payable by us in 2017, based on 2017 tax rates in effect. In addition, if all the shares of TW Securities had been sold on December 31, 2017 in order to fund the aggregate redemption amount, capital gains taxes of approximately $297 million would have been payable by us in 2017, based on 2017 tax rates in effect. Similarly, a significant amount of exchanges of ZENS by ZENS holders could adversely impact our cash flows. This could happen if our creditworthiness were to drop or the market for the ZENS were to become illiquid, or for some other reason. While funds for the payment of cash upon exchange of ZENS could be obtained from the sale of the shares of TW Securities that we own or from other sources, ZENS exchanges result in a cash outflow because tax deferrals related to the ZENS and TW Securities shares would typically cease when ZENS are exchanged and TW Securities shares are sold.

Risk Factors Affecting Our Electric Transmission & Distribution Business

Rate regulation of Houston Electric’s business may delay or deny Houston Electric’s ability to earn an expected return and fully recover its costs.

Houston Electric’s rates are regulated by certain municipalities and the PUCT based on an analysis of its invested capital, its expenses and other factors in a test year in comprehensive base rate proceedings (i.e., general rate cases) subject to periodic review and adjustment. Each of these rate proceedings is subject to third-party intervention and appeal, and the timing of a general base rate proceeding may be out of Houston Electric’s control. The rates that Houston Electric is allowed to charge may not match its costs at any given time, which is referred to as “regulatory lag.”

Though several interim rate adjustment mechanisms have been implemented to reduce the effects of regulatory lag, these adjustment mechanisms are subject to the applicable regulatory body’s approval and are subject to limitations that may reduce Houston Electric’s ability to adjust rates. For example, the DCRF mechanism adjusts an electric utility’s rates for increases in net distribution-invested capital (e.g., distribution plant and intangible plant and communication equipment) since its last comprehensive base rate proceeding, but Houston Electric may only make a DCRF filing once per calendar year. The TCOS


mechanism allows a transmission service provider to update its wholesale transmission rates to reflect changes in transmission-related invested capital, but is only available twice per calendar year.

Houston Electric can make no assurance that filings for such mechanisms will result in favorable adjustments to rates. Notwithstanding the application of the rate mechanisms discussed above, the regulatory process by which rates are determined is subject to change as a result of the legislative process or rulemaking, as the case may be, and may not always be available or result in rates that will produce recovery of Houston Electric’s costs or enable Houston Electric to earn an expected return. In addition, changes to the interim adjustment mechanisms could result in an increase in regulatory lag or otherwise impact Houston Electric’s ability to recover its costs in a timely manner. To the extent the regulatory process does not allow Houston Electric to make a full and timely recovery of appropriate costs, its results of operations, financial condition and cash flows could be adversely affected.

Disruptions at power generation facilities owned by third parties could interrupt Houston Electric’s sales of transmission and distribution services.

Houston Electric transmits and distributes to customers of REPs electric power that the REPs obtain from power generation facilities owned by third parties. Houston Electric does not own or operate any power generation facilities. If power generation is disrupted or if power generation capacity is inadequate, Houston Electric’s sales of transmission and distribution services may be diminished or interrupted, and its results of operations, financial condition and cash flows could be adversely affected.

Houston Electric’s revenues and results of operations are seasonal.

A significant portion of Houston Electric’s revenues is derived from rates that it collects from each REP based on the amount of electricity it delivers on behalf of such REP. Thus, Houston Electric’s revenues and results of operations are subject to seasonality, weather conditions and other changes in electricity usage, with revenues generally being higher during the warmer months. Unusually mild weather in the warmer months could diminish our results of operations and harm our financial condition. Conversely, extreme warm weather conditions could increase our results of operations in a manner that would not likely be annually recurring.

Houston Electric could be subject to higher costs and fines or other sanctions as a result of mandatory reliability standards.

The FERC has jurisdiction with respect to ensuring the reliability of electric transmission service, including transmission facilities owned by Houston Electric and other utilities within ERCOT. The FERC has designated the NERC as the ERO to promulgate standards, under FERC oversight, for all owners, operators and users of the bulk power system. The FERC has approved the delegation by the NERC of authority for reliability in ERCOT to the Texas RE, a Texas non-profit corporation. Compliance with the mandatory reliability standards may subject Houston Electric to higher operating costs and may result in increased capital expenditures. In addition, if Houston Electric were to be found to be in noncompliance with applicable mandatory reliability standards, it could be subject to sanctions, including substantial monetary penalties.

A substantial portion of Houston Electric’s receivables is concentrated in a small number of REPs, and any delay or default in such payments could adversely affect Houston Electric’s cash flows, financial condition and results of operations.

Houston Electric’s receivables from the distribution of electricity are collected from REPs that supply the electricity Houston Electric distributes to their customers. As of December 31, 2017, Houston Electric did business with approximately 68 REPs. Adverse economic conditions, 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. Applicable regulatory provisions require that customers be shifted to another REP or a provider of last resort if a REP cannot make timely payments. Applicable PUCT regulations significantly limit the extent to which Houston Electric can apply normal commercial terms or otherwise seek credit protection from firms desiring to provide retail electric service in its service territory, and Houston Electric thus remains at risk for payments related to services provided prior to the shift to another REP or the provider of last resort. A significant portion of Houston Electric’s billed receivables from REPs are from affiliates of NRG and Vistra Energy Corp., formerly known as TCEH Corp. Houston Electric’s aggregate billed receivables balance from REPs as of December 31, 2017 was $215 million Approximately 34% and 12% of this amount was owed by affiliates of NRG and Vistra Energy Corp., respectively. Any delay or default in payment by REPs could adversely affect Houston Electric’s cash flows, financial condition and results of operations. 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 by creditors involving payments Houston Electric had received from such REP.




The AMS deployed throughout Houston Electric’s service territory may experience unexpected problems with respect to the timely receipt of accurate metering data.

Houston Electric has deployed an AMS throughout its service territory, which integrates equipment and computer software from various vendors to eliminate the need for physical meter readings to be taken at consumers’ premises, such as monthly readings for billing purposes and special readings associated with a customer’s change in REPs or the connection or disconnection of electric service. Unanticipated difficulties could be encountered during the operation of the AMS, including failures or inadequacy of equipment or software, difficulties in integrating the various components of the AMS, changes in technology, cyber-security issues and factors outside the control of Houston Electric, which could result in delayed or inaccurate metering data that might lead to delays or inaccuracies in the calculation and imposition of delivery or other charges, which could have a material adverse effect on Houston Electric’s results of operations, financial condition and cash flows.

Risk Factors Affecting Our Natural Gas Distribution and Energy Services Businesses

Rate regulation of CERC’s business may delay or deny CERC’s ability to earn an expected return and fully recover its costs.

CERC’s rates for NGD are regulated by certain municipalities (in Texas only) and state commissions based on an analysis of NGD’s invested capital, expenses and other factors in a test year (often either fully or partially historic) in comprehensive base rate proceedings, subject to periodic review and adjustment. Each of these proceedings is subject to third-party intervention and appeal, and the timing of a general base rate proceeding may be out of CERC’s control. Thus, the rates that CERC is allowed to charge may not match its costs at any given time, resulting in what is referred to as “regulatory lag.”

Though several interim rate adjustment mechanisms have been approved by jurisdictional regulatory authorities and implemented by NGD to reduce the effects of regulatory lag, such adjustment mechanisms are subject to the applicable regulatory body’s approval and are subject to certain limitations that may reduce NGD’s ability to adjust its rates.

Arkansas allows public utilities to elect to have their rates regulated pursuant to a FRP, providing for a utility’s base rates to be adjusted once a year. In each of Louisiana, Mississippi and Oklahoma, NGD makes annual filings utilizing various formula rate mechanisms that adjust rates based on a comparison of authorized return to actual return to achieve the allowed return rates in those jurisdictions. Additionally, in Minnesota, the MPUC implemented a full revenue decoupling pilot program, which separates approved revenues from the amount of natural gas used by its customers. The effectiveness of these filings and programs depends on the approval of the applicable state regulatory body.

In Texas, NGD’s Houston, South Texas, Beaumont/East Texas and Texas Coast divisions each submit annual GRIP filings to recover the incremental capital investments made in the preceding year. NGD must file a general rate case no later than five years after the initial GRIP implementation date.

NGD can make no assurance that filings for such mechanisms will result in favorable adjustments to rates. Notwithstanding the application of the rate mechanisms discussed above, the regulatory process by which rates are determined is subject to change as a result of the legislative process or rulemaking, as the case may be, and may not always be available or result in rates that will produce recovery of NGD’s costs or enable NGD to earn an expected return. In addition, changes to the interim adjustment mechanisms could result in an increase in regulatory lag or otherwise impact NGD’s ability to recover its costs in a timely manner. Additionally, inherent in the regulatory process is some level of risk that jurisdictional regulatory authorities may initiate investigations of the prudence of operating expenses incurred or capital investments made by NGD and deny the full recovery of NGD’s cost of service or the full recovery of incurred natural gas costs in rates. To the extent the regulatory process does not allow NGD to make a full and timely recovery of appropriate costs, its results of operations, financial condition and cash flows could be adversely affected.

Access to natural gas supplies and pipeline transmission and storage capacity are essential components of reliable service for CERC’s customers.

CERC depends on third-party service providers to maintain an adequate supply of natural gas and for available storage and intrastate and interstate pipeline capacity to satisfy NGD’s customers’ needs, all of which are critical to system reliability. CERC purchases substantially all of NGD’s natural gas supply from intrastate and interstate pipelines. If CERC is unable to secure an independent natural gas supply of its own or through its affiliates or if third-party service providers fail to timely deliver natural gas to meet NGD’s requirements, the resulting decrease in CERC’s natural gas supply in its service territories could have a material adverse effect on its results of operations, cash flows and financial condition. Additionally, a significant disruption, whether through reduced intrastate and interstate pipeline transmission or storage capacity or other events affecting natural gas supply, including, but not limited to, operational failures, hurricanes, tornadoes, floods, acts of terrorism or cyber-attacks or changes in legislative


or regulatory requirements, could also adversely affect CERC’s business. Further, to the extent that CERC’s natural gas requirements cannot be met through access to or continued use of existing natural gas infrastructure or if additional infrastructure, including onshore and offshore exploration and production facilities, gathering and processing systems and pipeline and storage capacity is not constructed at a rate that satisfies demand, then CERC’s NGD growth could be negatively affected.

CERC’s NGD and Energy Services business, including transportation and storage, whether through the use of AMAs or other arrangements, are subject to fluctuations in notional natural gas prices as well as geographic and seasonal natural gas price differentials, which could affect the ability of CERC’s suppliers and customers to meet their obligations or otherwise adversely affect CERC’s liquidity, results of operations and financial condition.

CERC is subject to risk associated with changes in the notional price of natural gas as well as geographic and seasonal natural gas price differentials that impact our business, including transportation and storage, whether through the use of AMAs or other arrangements. Increases in natural gas prices might affect CERC’s ability to collect balances due from its customers and, for NGD, could create the potential for uncollectible accounts expense to exceed the recoverable levels built into CERC’s tariff rates. In addition, a sustained period of high natural gas prices could (i) decrease demand for natural gas in the areas in which CERC operates, thereby resulting in decreased sales and revenues and (ii) increase the risk that CERC’s suppliers or customers fail or are unable to meet their obligations. An increase in natural gas prices would also increase CERC’s working capital requirements by increasing the investment that must be made to maintain natural gas inventory levels. Additionally, a decrease in natural gas prices could increase the amount of collateral that CERC must provide under its hedging arrangements. AMAs may be subject to regulatory approval, and such agreements may not be renewed or may be renewed with less favorable terms.

A decline in CERC’s credit rating could result in CERC having to provide collateral under its shipping or hedging arrangements or to purchase natural gas, which consequently would increase its cash requirements and adversely affect its financial condition.

If CERC’s credit rating were to decline, it may have an adverse impact on the cost of borrowings and, in extraordinary market conditions, it may limit the ability to access the debt capital markets. Additionally, CERC might be required to post cash collateral under its shipping or hedging arrangements or to purchase natural gas. If a credit rating downgrade and the resultant cash collateral requirement were to occur at a time when CERC was experiencing significant working capital requirements or otherwise lacked liquidity, CERC’s financial condition, results of operations financial condition and cash flows could be adversely affected.


CERC’sCenterPoint Energy’s previously owned Energy Systems Group business has performance and warranty obligations, some of which are guaranteed by CenterPoint Energy.

On June 30, 2023, CenterPoint Energy closed the sale of its Energy Systems Group business. Prior to June 30, 2023 and as part of the normal course of its business, Energy Systems Group issued performance bonds and other forms of assurance that committed it to operate facilities, pay vendors or subcontractors and support warranty obligations. As the parent company prior to the closing of the sale, CenterPoint Energy or Vectren guaranteed certain of its subsidiaries’ commitments. When Energy Systems Group was wholly owned by CenterPoint Energy, these guarantees did not represent incremental consolidated obligations, but rather, these guarantees represented guarantees of Energy Systems Group’s obligations to allow it to conduct business without posting other forms of assurance. Neither CenterPoint Energy nor Vectren has been called upon to satisfy any obligations pursuant to these parental guarantees to date, but may be required to do so in the future. For further information, see Note 15(c) to the consolidated financial statements.

An impairment of goodwill, long-lived assets, including intangible assets, equity method investments and an impairment or fair value adjustment could reduce our earnings.

Long-lived assets, including intangible assets with finite useful lives, are reviewed for impairment whenever events or changes in circumstances indicate the carrying value may not be recoverable. Goodwill is tested for impairment at least annually, as well as when events or changes in circumstances indicates the carrying value may not be recoverable. While CenterPoint Energy has identified and recorded goodwill impairments in the past, no impairments to goodwill were recorded during the years ended December 31, 2023, 2022 and 2021. See Note 6 to the consolidated financial statements for further information. Should the annual goodwill impairment test or another periodic impairment test or an observable transaction indicate the fair value of our assets is less than the carrying value, we would be required to take a non-cash charge to earnings with a correlative effect on equity, increasing balance sheet leverage as measured by debt to total capitalization. A non-cash impairment charge or fair value adjustment could adversely impact our financial condition and results of operations.

If CenterPoint Energy redeems the ZENS prior to their maturity in 2029, its ultimate tax liability and redemption payments would result in significant cash payments, which would adversely impact its cash flows. Similarly, a significant amount of exchanges of ZENS by ZENS holders could adversely impact CenterPoint Energy’s cash flows.

CenterPoint Energy has approximately $828 million principal amount of ZENS outstanding as of December 31, 2023. 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. CenterPoint Energy may redeem all of the ZENS at any time at a redemption amount per ZENS equal to the higher of the contingent principal amount per ZENS ($18 million in the aggregate, or $1.24 per ZENS, as of December 31, 2023), or the sum of the current market value of the reference shares attributable to one ZENS at the time of redemption. In the event CenterPoint Energy redeems the ZENS, in addition to the redemption amount, it would be required to pay deferred taxes related to the ZENS. CenterPoint Energy’s ultimate tax liability related to the ZENS and ZENS-
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Related Securities continues to increase by the amount of the tax benefit realized each year. If the ZENS had been redeemed on December 31, 2023, deferred taxes of approximately $728 million would have been payable in 2023, based on 2023 tax rates in effect. In addition, if all the shares of ZENS-Related Securities had been sold on December 31, 2023 to fund the aggregate redemption amount, capital gains taxes of approximately $81 million would have been payable in 2023. Similarly, a significant amount of exchanges of ZENS by ZENS holders could adversely impact CenterPoint Energy’s cash flows. This could happen if CenterPoint Energy’s creditworthiness were to drop, the market for the ZENS were to become illiquid, or for some other reason. While funds for the payment of cash upon exchange of ZENS could be obtained from the sale of the shares of ZENS-Related Securities CenterPoint Energy owns or from other sources, ZENS exchanges result in a cash outflow because tax deferrals related to the ZENS and ZENS-Related Securities shares would typically be disposed when ZENS are exchanged and ZENS-Related Securities shares are sold.

Our potential business strategies and strategic initiatives, including merger and acquisition activities and the disposition of assets or businesses, may not be completed or perform as expected, adversely affecting our financial condition, results of operations and cash flows.

Our financial condition, results of operations and cash flows depend, in part, on our management’s ability to implement our business strategies successfully and realize the anticipated benefits therefrom. In 2021, we announced our strategic goals for CenterPoint Energy, including our ten-year capital plan, and net zero and carbon emission reductions goals. Our strategic goals are subject to the risks described in this section and various assumptions. These assumptions may be proven incorrect or we may not be able to execute on these strategic goals in a timely manner or at all. If we are unable to execute on our strategic goals, including our ten-year capital plan, the benefits therefrom may not be fully realized, if at all, and our reputation may be adversely affected.

From time to time we have made, and may continue to make, acquisitions or divestitures of businesses and assets, such as our proposed sale of our Louisiana and Mississippi natural gas local distribution companies, our completed sale of our Energy Systems Group business, form joint ventures or undertake restructurings, such as the Restructuring. However, suitable acquisition candidates or potential buyers may not continue to be available on terms and conditions we find acceptable, or the expected benefits of completed acquisitions or dispositions may not be realized fully or at all, or may not be realized in the anticipated timeframe. If we are unable to make acquisitions, or if those acquisitions do not perform as anticipated, our future growth may be adversely affected. Further, any completed or future acquisitions or dispositions involve substantial risks, including the following:

•acquired businesses or assets may not produce revenues, earnings or cash flow at anticipated levels;
•acquired businesses or assets could have environmental, permitting or other problems for which contractual protections prove inadequate;
•we may assume liabilities that were not disclosed to us, that exceed our estimates, or for which our rights to indemnification from the seller are limited;
•we may be unable to integrate acquired businesses successfully and realize anticipated economic, operational and other benefits in a timely manner, which could result in substantial costs and delays or other operational, technical or financial problems;
•acquisitions or dispositions, or the pursuit of such transactions, including any separation or disentanglement efforts or requirements, such as the provision of transition services, could disrupt our ongoing businesses, distract management, divert resources and make it difficult to maintain current business standards, controls and procedures; and
•we may not receive regulatory approvals necessary to complete an acquisition or disposition in a timely manner or at all.

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 local distribution company businesses. The transaction is expected to close in the first quarter of 2025. For further information, see Note 21 to the consolidated financial statements. We can make no assurances regarding the completion of this sale, which could be subject to delays or otherwise not consummated.

Changing demographics, poor investment performance of pension plan assets and other factors adversely affecting the calculation of pension liabilities could unfavorably impact our financial condition, results of operations and liquidity.

CenterPoint Energy and its subsidiaries maintain qualified defined benefit pension plans covering certain of its employees. Costs associated with these plans are dependent upon a number of factors including the investment returns on plan assets, the level of interest rates used to calculate the funded status of the plan, contributions to the plan, the number of plan participants and government regulations with respect to funding requirements and the calculation of plan liabilities. Funding requirements may increase and CenterPoint Energy may be required to make unplanned contributions in the event of a decline in the market
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value of plan assets, a decline in the interest rates used to calculate the present value of future plan obligations, or government regulations that increase minimum funding requirements or the pension liability. In 2023, 2022 and 2021, CenterPoint Energy had a settlement expense for its pension plans as a result of an increase in eligible employee retirements and pension plan distributions. See Note 8 to the consolidated financial statements for further information. In addition to affecting CenterPoint Energy’s funding requirements, these factors could adversely affect our financial condition, results of operations and liquidity.

We may be significantly affected by changes in federal income tax laws and regulations, including any comprehensive federal tax reform legislation.

Our businesses are impacted by U.S. federal income tax policy. The TCJA, CARES Act, and the IRA significantly changed the U.S. Internal Revenue Code, including taxation of U.S. corporations, by among other things, reducing the federal corporate income tax rate, limiting interest deductions, altering the expensing of capital expenditures, enacting a new CAMT, and expanding federal tax credits for cleaner energy production. Based on information and forecasts as of December 31, 2023, the Registrants will be subject to the CAMT included in the IRA.

The interpretive guidance issued by the IRS and state tax authorities may be inconsistent with our interpretation and the legislation could be subject to amendments, which could lessen or increase certain impacts of the legislation. In addition, the retail regulatory treatment of the expanded tax credits and CAMT could impact the Registrants’ future cash flows, and this legislation could result in unintended consequences not yet identified that could have an adverse impact on the Registrants’ financial results and future cash flows.

Further federal tax reform legislation could be enacted that may significantly change the federal income tax laws applicable to domestic businesses, including changes that may increase the federal income tax rate and impact investment incentives and deductions for depreciation and interest, among other deductions. While CenterPoint Energy and its subsidiaries cannot assess the overall impact of any such potential legislation on our businesses, it is possible that our financial condition, results of operations or cash flows could be negatively impacted. Furthermore, with any enacted federal tax reform legislation, it is uncertain how state commissions and local municipalities may require us to respond to the effects of such tax legislation, including determining the treatment of EDIT and other increases and decreases in our revenue requirements. As such, potential regulatory actions in response to any enacted tax legislation could adversely affect our financial condition, results of operations and cash flows.

Risk Factors Affecting Safety and Security Risks

The Registrants’ businesses have safety risks.

The Registrants’ facilities and distribution and transmission systems have been and may in the future be involved in incidents that result in injury, death, or property loss to employees, customers, third parties, or the public. Although the Registrants have insurance coverage for many potential incidents, depending upon the nature and severity of any incident, they could experience financial loss, claims and litigation, damage to their reputation, and negative consequences from regulatory authorities or other public authorities. Further, certain CenterPoint Energy employees who work in the field have experienced threats of violence during the performance of their work. Threats of violence, actual violence and other concerns may result in field employees being unable or unwilling to complete critical functions, which could adversely affect our businesses, financial condition and results of operations, and could make it harder to recruit and retain certain employees.

Cyberattacks, physical security breaches, acts of terrorism or other disruptions could adversely impact our reputation, financial condition, results of operations and cash flows.

We are subject to cyber and physical security risks related to our information technology systems, operational technology, network infrastructure, and other technology and facilities used to conduct almost all of our businesses. For example, the operation of our electric generation, transmission and distribution systems are dependent on not only physical interconnection of our facilities but also on communications among the various components of our systems and third-party systems. This reliance on information and communication between and among those components has increased since deployment of the intelligent grid, smart devices and operational technologies across our businesses. Further, certain of the various internal systems we use to conduct our businesses are highly integrated. Consequently, a cyberattack or unauthorized access in any one of these systems could potentially impact the other systems. Similarly, our business operations are interconnected with external networks and facilities. For example, the operation of an efficient deregulated wholesale and retail electric market in Texas mandates communication with ERCOT, and competitive retailers; and our Indiana Electric organization has a similar relationship with MISO. Also, the distribution of natural gas to our customers requires communications with third-party
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systems. Disruption of those communications, whether caused by physical disruption such as storms or other natural disasters, by failure of equipment or technology or by man-made events, such as cyberattacks or acts of terrorism, may disrupt our ability to conduct operations and control assets.

The sophistication of cybersecurity threats, including those leveraging AI, continues to increase, and the controls and preventative actions we take to reduce the risk of cybersecurity incidents and protect our systems, including the regular testing of our cybersecurity incident response plan, may be insufficient. In addition, new technology that could result in greater operational efficiency, such as our use of AI, may further expose our computer systems to the risk of cybersecurity incidents. Cyberattacks, including phishing attacks and threats from the use of malware, ransomware and viruses or malicious code, and unauthorized access could also result in the loss, or unauthorized use, of confidential, proprietary or critical infrastructure data or security breaches of other information technology systems that could disrupt operations and critical business functions, adversely affect reputation, impact our customers, increase costs and subject us to possible legal claims and liability. While we have implemented and maintain a cybersecurity program designed to protect our information technology, operational technology, and data systems from such attacks, our cybersecurity program does not prevent all breaches or cyberattack incidents. We have experienced an increase in the number of attempts by external parties to access our networks or our company data without authorization. We have also experienced, and expect to continue to experience, cyber intrusions and attacks to our information systems and those of third parties, including vendors, suppliers, contractors and quasi government entities who perform certain services for us or administer and maintain our sensitive information. These prior intrusions and attacks have not had a material impact on our business, results of operations, or financial condition. Because technology is increasingly complex and cyberattacks are increasingly sophisticated and more frequent, there is a risk such incidents could have an adverse effect on us in the future. The risk of a disruption or breach of our operational technology systems, or the compromise of the data processed in connection with our operations, through a cybersecurity breach or ransomware attack, has increased as attempted attacks have advanced in sophistication and number around the world. We are not fully insured against all cybersecurity risks, any of which could adversely affect our reputation and could have an adverse effect on our financial condition, results of operations and cash flows.

We depend on the secure operations of our physical assets to transport the energy we deliver and our information technology to process, transmit and store electronic information, including information and operational technology we use to safely operate our energy transportation systems. Security breaches, attacks on our infrastructure and facilities, including against the Registrants or as a means to harm a third-party by disrupting the transmission and distribution of energy, or acts of terrorism, including by foreign or domestic actors, could expose our business to a risk of loss, misuse or interruption of critical physical assets or information and functions that affect our operations, as well as potential data privacy breaches and loss of protected personal information and other sensitive information, such as Critical Energy Infrastructure Information. Such losses could result in operational impacts, damage to our assets, public or personal safety incidents, impacts to our customers, damage to the environment, reputational harm, competitive disadvantage, regulatory enforcement actions, litigation and a potential adverse effect on our operations, financial condition, results of operations and cash flows. There is no certainty that costs incurred related to actual or thwarted cyberattacks, or for the safeguarding against such security threats, will be recoverable through rates.

Compliance with and changes in cybersecurity laws and regulations have a cost and operational impact on our business, and failure to comply with such requirements could adversely impact our reputation, financial condition, results of operations and cash flows.

Cyberattacks are becoming more sophisticated, and U.S. government warnings have indicated infrastructure assets, including pipelines and electric generation and infrastructure, may be specifically targeted by certain groups. The TSA announced two new security directives in the second and third quarters of 2021. These directives required critical pipeline owners to comply with mandatory reporting measures, designate a cybersecurity coordinator, provide vulnerability assessments, and ensure compliance with certain cybersecurity requirements. In the third quarter of 2022, the TSA made significant updates to one of the security directives to require critical pipeline owners to establish and implement a TSA-approved Cybersecurity Implementation Plan, develop and maintain a Cybersecurity Incident Response Plan, and establish a Cybersecurity Assessment Plan. The TSA approved CenterPoint Energy’s Cybersecurity Implementation Plan in December 2022. The TSA further updated and renewed the pipeline security directive in July 2023 with updated requirements for Pipeline Cybersecurity Mitigation Actions, Contingency Planning, and Testing. CenterPoint Energy continues to take measures to comply with the TSA pipeline security directive requirements. We may be required to expend significant additional resources and costs to respond to cyberattacks, to continue to modify or enhance our protective measures, or to assess, investigate and remediate any critical infrastructure security vulnerabilities. There is no certainty that such costs incurred will be recovered through rates. Any failure to remain in compliance with these government regulations or failure in our cybersecurity protective measures may result in enforcement actions which may have an adverse effect on our reputation, financial condition, results of operations and cash flows.
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Failure to maintain the security of personal information could adversely affect us.

In connection with our businesses, we and our third parties (vendors, suppliers, and contractors) collect and retain personal information (for example, information of our customers, shareholders, suppliers and employees), and there is an expectation that we and such third parties will adequately protect that information. The regulatory environment surrounding information security and data privacy continues to evolve and is increasingly demanding. New laws and regulations governing data privacy and the unauthorized disclosure of confidential information pose increasingly complex compliance challenges and elevate our costs. Any failure by us to comply with these laws and regulations, including as a result of a security or privacy breach, could result in significant costs, fines and penalties and liabilities for us. While we have implemented and maintain a cybersecurity program designed to protect our information technology, operational technology, and data systems from attacks, and while we have implemented and maintain a data privacy program designed to manage and protect personal information, neither program can prevent all security or privacy breaches. We and some of our third parties that maintain personal information have experienced, and expect to continue to experience, data privacy incidents and breaches; however, to date, we have not experienced a material data privacy incident or breach. A significant theft, loss or fraudulent use of the personal information we maintain, or failure of our vendors, suppliers and contractors to use or maintain such data in accordance with contractual provisions and other legal requirements, could adversely impact our reputation and could result in significant costs, fines and penalties and liabilities for us. Additionally, if we acquire a company that has violated or is not in compliance with applicable data protection privacy, we may incur significant liabilities and penalties as a result.

We may not be successful in our adoption of AI, which could adversely affect our business, reputation, or financial results.

We are using and exploring the further use of AI, including generative AI, and its ability to enhance the services we offer to the communities we serve. There are significant risks involved in developing and deploying AI, and there can be no assurance that the use of AI will enhance our services or be beneficial to our business, including with respect to the efficiency and resiliency of our systems. For example, our AI-related efforts may give rise to risks related to harmful content, accuracy, bias, discrimination, toxicity, intellectual property infringement or misappropriation, defamation, data privacy, and cybersecurity, among others. In addition, the adoption of AI may subject us to new or enhanced governmental or regulatory scrutiny, new or amended laws, rules, directives, and regulations governing the use of AI, litigation, ethical concerns, negative consumer perceptions as to automation and AI, or other complications that could adversely affect our business, reputation, or financial results. We may not be able to recover our investments in AI technology through our regulatory proceedings, and our use of AI may subject us to legal liability. Similarly, as AI continues to evolve we may not be able to adopt and implement AI as quickly as our customers or communities desire or regulators may require, which could also adversely affect us. AI is a relatively new and rapidly evolving technology, and we are unable to predict all of the risks that may result from the adoption of our AI initiatives.

General and Other Risks

Our revenues and results of operations are seasonal.


A substantial portion of CERC’s revenues is derived from natural gas sales. Thus, CERC’sHouston Electric’s, Indiana Electric’s and Natural Gas’ revenues and results of operations are subject to seasonality, weather conditions and other changes in electricity and natural gas usage, withas applicable. Houston Electric’s revenues beingare generally higher during the winterwarmer months. UnusuallyAs in certain past years, unusually mild weather in the winterwarmer months could diminish ourHouston Electric’s results of operations and harm ourits financial condition. Conversely, as in certain past years, extreme coldwarm weather conditions could increase ourHouston Electric’s results of operations in a manner that would not likely be annually recurring. A significant portion of Indiana Electric’s sales are for space heating and cooling. Consequently, as in certain past years, Indiana Electric’s results of operations may be adversely affected by warmer-than-normal heating season weather or colder-than-normal cooling season weather, while, as has occurred in certain past years, more extreme seasonal weather conditions could increase Indiana Electric’s results of operations in a manner that would not likely be annually recurring. Natural Gas’ revenues are customarily higher during the winter months. As in certain past years, unusually mild weather in the winter months could diminish Natural Gas’ results of operations and harm its financial condition. Conversely, as occurred in certain past years, extreme cold weather conditions could increase its results of operations in a manner that would not likely be annually recurring. For information related to weather normalization regulatory mechanisms and weather hedges, see Note 9(a) to the consolidated financial statements. For additional risks related to the February 2021 Winter Storm Event, see Note 7 to the consolidated financial statements for further information.


The states
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Climate change could adversely impact financial results from our businesses and result in which CERC provides regulated local natural gas distribution may, either through legislation or rules, adopt restrictions regarding organization, financingmore frequent and affiliate transactionsmore severe weather events that could have significant adverse impacts on CERC’s ability to operate.adversely affect our results of operations.


From time to time, proposals have been put forth in some of the states in which CERC does business to give state regulatory authorities increased jurisdictionA changing climate creates uncertainty and scrutiny over organization, capital structure, intracompany relationships and lines of business that could be pursued by registered holding companies and their affiliates that operate in those states. Some of these frameworks attempt to regulate financing activities, acquisitions and divestitures, and arrangements between the utilities and their affiliates, and to restrict the level of non-utility business that can be conducted within the holding company structure. Additionally, they may impose record-keeping, record access, employee training and reporting requirements related to affiliate transactions and reporting in the event of certain downgrading of the utility’s credit rating.

These regulatory frameworks could have adverse effects on CERC’s ability to conduct its utility operations, to finance its business and to provide cost-effective utility service. In addition, if more than one state adopts restrictions on similar activities, it may be difficult for CERC and us to comply with competing regulatory requirements.

CERC’s businesses must compete with alternate energy sources, which could result in CERC marketingbroad changes, both physical and financial in nature, to our service territories and our business. If climate changes occur that result in warmer temperatures than normal in our service territories, financial results from our businesses could be adversely impacted. For example, where natural gas is used to heat homes and businesses, warmer weather might result in less natural gas being used, adversely affecting us. Another possible result of climate change is more frequent and more severe weather events, such as hurricanes, tornadoes, and severe winter weather conditions, including ice storms, all of which may impact our operations and ability to serve our customers. To the extent the frequency and severity of extreme weather events increases, our costs of providing service may increase, including the costs and availability of procuring insurance related to such impacts, and those costs may not be recoverable. Further, events of extreme weather could make it unsafe or hinder the effectiveness of our employees to fix, maintain and restore power to affected areas and could harm our reputation. Since certain of our facilities are located along or near the Texas gulf coast, increased or more severe hurricanes or tornadoes could increase our costs to repair damaged facilities and restore service to our customers. Our Electric and Natural Gas operations in our service territories were both also impacted by the February 2021 Winter Storm Event and could experience a similar event in the future, which could have an adverse impact on CERC’sour financial condition, results of operations financial condition and cash flows.

CERC competes primarily with alternate energy sources In the long term, climate change could also cause shifts in population, including customers moving away from our service territories. When we cannot deliver electricity or natural gas to customers or our customers cannot receive our services, our financial results are impacted by lost revenues, and we generally must seek approval from regulators to recover restoration costs. To the extent we are unable to recover those costs or recover in a timely manner, or if recovery of such costs results in higher rates and reduced demand for our services, our future financial results may be adversely impacted. Similarly, public and private efforts to address climate change, such as electricityby legislation, regulation, actions by private interest groups, and litigation, could impact our ability to continue operating our businesses as we do today, significant aspects of which rely on fossil fuels. These initiatives could have a significant impact on us and our operations as well as on our third-party suppliers, vendors and partners, which could impact us by among other things, causing permitting and construction delays, project cancellations or increased project costs passed on to us. For further information on these initiatives, please see “— We are subject to operational…” Finally, we may be subject to climate change litigation, which could result in substantial fines, penalties or damages and restrictions on our operations. The oil and gas industry has already faced such litigation, challenging its marketing and use of fossil fuels and attributing climate change to emissions resulting from the use of fossil fuels, and other fuel sources. In some areas, intrastate pipelines,industries, including ours, could face such litigation in the future. For more information, see Note 7 to the consolidated financial statements, and “— CenterPoint Energy is subject to operational and financial risks...”

We are exposed to risks related to reduction in energy consumption due to factors such as changes in customers’ perceptions from incidents of other utilities.

Our businesses are affected by reduction in energy consumption due to factors including economic, climate and market conditions in our service territories, energy efficiency initiatives, use of alternative technologies and changes in our customers’ perceptions regarding natural gas distributors and marketers also compete directly with CERC for natural gas sales to end users. In


addition,usage as a result of federal regulatory changes affecting interstate pipelines,incidents of other utilities involving natural gas marketers operating on these pipelines, may be ablewhich could impact our ability to bypass CERC’s facilitiesgrow our customer base and market, sell and/or transportour rate of growth. Growth in customer accounts and growth of customer usage each directly influence demand for electricity and natural gas directly to commercial and industrial customers. Any reduction in the amountneed for additional delivery facilities. Customer growth and customer usage are affected by a number of factors outside our control, such as mandated energy efficiency measures, bans on or further regulation of natural gas-fired appliances, demand-side management goals, distributed generation resources and economic and demographic conditions, including population changes, job and income growth, housing starts, new business formation and the overall level of economic activity. Declines in demand for electricity and natural gas marketed, soldin our service territories due to pipeline incidents of other utilities, increased electricity and natural gas prices as experienced during the February 2021 Winter Storm Event and during periods of persisting high inflation or transported by CERCeconomic downturns, among other factors, could reduce overall usage and lessen cash flows, especially as industrial customers reduce production and, therefore, consumption of electricity and natural gas. Although Houston Electric’s and Indiana Electric’s transmission and distribution businesses are subject to regulated allowable rates of return and recovery of certain costs under periodic adjustment clauses, overall declines in electricity delivered and used as a result of competitioneconomic downturn or recession could reduce revenues and cash flows, thereby diminishing results of operations. A reduction in the rate of economic, employment and/or population growth could result in lower growth and reduced demand for and usage of electricity and natural gas in such service territories. Some or all of these factors could result in a lack of growth or decline in customer demand for electricity or natural gas or number of customers and may result in our failure to fully realize anticipated benefits from significant capital investments and expenditures, which could have an adverse impact on CERC’s results of operations, financial condition and cash flows.

Risk Factors Affecting Our Interests in Enable Midstream Partners, LP

We hold a substantial limited partner interest in Enable (54.1% of the outstanding common units representing limited partner interests in Enable as of December 31, 2017), as well as 50% of the management rights in Enable’s general partner and a 40% interest in the incentive distribution rights held by Enable’s general partner. As of December 31, 2017, we owned an aggregate of 14,520,000 Series A Preferred Units representing limited partner interests in Enable. Accordingly, our future earnings, results of operations, cash flows and financial condition will be affected by the performance of Enable, the amount of cash distributions we receive from Enable and the value of our interests in Enable. Factors that may have a material impact on Enable’s performance and cash distributions, and, hence, the value of our interests in Enable, include the risk factors outlined below, as well as the risks described elsewhere under “Risk Factors” that are applicable to Enable.

Our cash flows will be adversely impacted if we receive less cash distributions from Enable than we currently expect.

Both CERC Corp. and OGE hold their limited partner interests in Enable in the form of common units. We also hold Series A Preferred Units in Enable. For its Series A Preferred Units, Enable is expected to pay $0.625 per Series A Preferred Unit, or $2.50 per Series A Preferred Unit on an annualized basis. However, distributions on each Series A Preferred Unit are not mandatory and are non-cumulative in the event distributions are not declared on the Series A Preferred Units. Enable is expected to pay a minimum quarterly distribution of $0.2875 per unit, or $1.15 per unit on an annualized basis, on its outstanding common units to the extent it has sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to its general partner and its affiliates (referred to as “available cash”). Enable may not have sufficient available cash each quarter to enable it (i) to pay distributions on the Series A Preferred Units or (ii) maintain or increase the distributions on its common units. Additionally, distributions on the Series A Preferred Units reduce the amount of available cash Enable has to pay distributions on its common units. The amount of cash Enable can distribute on its common units and Series A Preferred Units will principally depend upon the amount of cash it generates from its operations, which will fluctuate from quarter to quarter based on, among other things:

the fees and gross margins it realizes with respect to the volume of natural gas, NGLs and crude oil that it handles;

the prices of, levels of production of, and demand for natural gas, NGLs and crude oil;

the volume of natural gas, NGLs and crude oil it gathers, compresses, treats, dehydrates, processes, fractionates, transports and stores;

the relationship among prices for natural gas, NGLs and crude oil;

cash calls and settlements of hedging positions;

margin requirements on open price risk management assets and liabilities;

the level of competition from other companies offering midstream services;

adverse effects of governmental and environmental regulation;

the level of its operation and maintenance expenses and general and administrative costs; and

prevailing economic conditions.

In addition, the actual amount of cash Enable will have available for distribution will depend on other factors, including:

the level and timing of its capital expenditures;

the cost of acquisitions;

its debt service requirements and other liabilities;



fluctuations in its working capital needs;

its ability to borrow funds and access capital markets;

restrictions contained in its debt agreements;

the amount of cash reserves established by its general partner;

distributions paid on its Series A Preferred Units;

any impact on cash levels should any sale of our investment in Enable occur; and

other business risks affecting its cash levels.

The amount of cash Enable has available for distribution to us on its common units and Series A Preferred Units depends primarily on its cash flow rather than on its profitability, which may prevent Enable from making distributions, even during periods in which Enable records net income.

The amount of cash Enable has available for distribution on its common units and Series A Preferred Units, depends primarily upon its cash flows and not solely on profitability, which will be affected by non-cash items. As a result, Enable may make cash distributions during periods when it records losses for financial accounting purposes and may not make cash distributions during periods when it records net earnings for financial accounting purposes.

Enable’s Series A Preferred Units are required to be redeemed in certain circumstances if they are not eligible for trading on the NYSE, and Enable may not have sufficient funds to redeem its Series A Preferred Units if required to do so.

As a holder of Enable’s Series A Preferred Units, we may request that Enable list those units for trading on the NYSE. If Enable is unable to list the Series A Preferred Units in certain circumstances, it will be required to redeem the Series A Preferred Units. There can be no assurance that Enable would have sufficient financial resources available to satisfy its obligation to redeem the Series A Preferred Units. In addition, mandatory redemption of the Series A Preferred Units could have a material adverse effect on Enable’s business,our financial position,condition, results of operations and cash flows.

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Aging infrastructure may lead to increased costs and disruptions in operations that could negatively impact our financial results.

We have risks associated with aging infrastructure assets, including the failure of equipment or processes and potential breakdowns due to such aging. The age of certain of our assets may result in a need for replacement or higher level of maintenance costs because of our risk based federal and state compliant integrity management programs. As part of our long-term capital plan, we continue to make upgrades to our aging infrastructure assets to enhance the reliability of our infrastructure. Failure to achieve timely and full recovery of expenses associated with our aging infrastructure could adversely impact revenues and could result in increased capital expenditures or expenses. In addition, the nature of information available on aging infrastructure assets may make inspections, maintenance, upgrading and replacement of the assets particularly challenging. Also, our ability to make quarterly cash distributionssuccessfully maintain or replace our aging infrastructure may be delayed or be at a greater cost than anticipated due to its unitholders.

Wesupply chain disruptions. Further, with respect to Natural Gas’ operations, if certain pipeline replacements (for example, cast-iron or bare steel pipe) are not able to exercise control over Enable, which entailscompleted timely or successfully, government agencies and private parties might allege the uncompleted replacements caused events such as fires, explosions or leaks. Although we maintain insurance for certain risks.

Enable is controlled jointly by CERC Corp. and OGE, who each own 50% of the management rightsour facilities, our insurance coverage may not be sufficient in the general partner of Enable. The board of directors of Enable’s general partnerevent a catastrophic loss is composed of an equal number of directors appointedalleged to have been caused by OGEa failure to timely complete equipment replacements. Insufficient insurance coverage and by us, the president and chief executive officer of Enable’s general partner and three directors who are independent as defined under the independence standards established by the NYSE. Accordingly, we are not able to exercise control over Enable.

Although we jointly control Enable with OGE, we may have conflicts of interest with Enable thatincreased insurance costs could subject us to claims that we have breachedadversely impact our fiduciary duty to Enable and its unitholders.

CERC Corp. and OGE each own 50% of the management rights in Enable’s general partner, as well as limited partner interests in Enable, and interests in the incentive distribution rights held by Enable’s general partner. We also hold Series A Preferred Units in Enable. Conflicts of interest may arise between us and Enable and its unitholders. Our joint control of the general partner of Enable may increase the possibility of claims of breach of fiduciary or contractual duties including claims of conflicts of interest related to Enable. In resolving these conflicts, we may favor our own interests and the interests of our affiliates over the interests of Enable and its unitholders as long as the resolution does not conflict with Enable’s partnership agreement. These circumstances could subject us to claims that, in favoring our own interests and those of our affiliates, we breached a fiduciary or contractual duty to Enable or its unitholders.

Enable’s contracts are subject to renewal risks.

As contracts with its existing suppliers and customers expire, Enable negotiates extensions or renewals of those contracts or enter into new contracts with other suppliers and customers. Enable may be unable to extend or renew existing contracts or enter into new contracts on favorable commercial terms, if at all. Depending on prevailing market conditions at the time of an extension or renewal, gathering and processing customers with fee based contracts may desire to enter into contracts under different fee arrangements and gathering and processing customers with contracts that contain minimum volume commitments may desire to


enter into contracts without minimum volume commitments. Likewise, Enable’s transportation and storage customers may choose not to extend or renew expiring contracts based on the economics of the related areas of production. To the extent Enable is unable to renew or replace its expiring contracts on terms that are favorable, if at all, or successfully manage its overall contract mix over time, its financial position,condition, results of operations and cash flows. Finally, aging infrastructure may complicate our utility operations ability to makeaddress climate change concerns and efforts to enhance resiliency and reliability. See “— Disruptions to the global supply...”
Our financial condition, results of operations and cash distributions couldflows may be adversely affected.affected if we are unable to successfully operate our facilities or perform certain corporate functions.


EnableOur performance depends on the successful operation of our facilities. Operating these facilities involves many risks inherent in the generation, transmission and distribution of electricity and in the delivery of natural gas that could result in substantial losses or other damages. From time to time, we have and may in the future experience various risks associated with the operations of our facilities, including, but not limited to, the following:

•operator error or failure of equipment or processes, including failure to follow appropriate safety protocols for, among others, the transmission and distribution of electricity and in the delivery of natural gas, including operations of our peak shaving, propane-air facilities;
•the handling of hazardous equipment or materials that could result in serious personal injury, loss of life and environmental and property damage;
•operating limitations that may be imposed by environmental or other regulatory requirements;
•labor disputes;
•information technology or financial and billing system failures, including those due to the implementation and integration of new technology, that impair our information technology infrastructure, reporting systems or disrupt normal business operations;
•compliance mandates that result in penalties from our regulators;
•failure to obtain in a small numbertimely manner and at reasonable prices the necessary fuel, such as coal and natural gas, building materials or other items needed to operate our facilities;
•information technology failure that affects our ability to access customer information or causes us to lose confidential or proprietary data that adversely affects our reputation or exposes us to legal claims; and
•catastrophic events such as fires, earthquakes, explosions, leaks, floods, droughts, hurricanes, ice storms, flooding, terrorism, wildfires, pandemic health events or other similar occurrences, including any environmental impacts related thereto, which catastrophic events may require participation in mutual assistance efforts by us or other utilities to assist in power restoration efforts.

Such events may result in a decrease or elimination of revenue from our facilities, an increase in the cost of operating our facilities or delays in cash collections, any of which could have an adverse effect on our financial condition, results of operations and cash flows. Such events have and may in the future result in the imposition of regulatory or environmental fines and increased litigation.

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Our businesses will continue to have to adapt to technological change and may not be successful or may have to incur significant expenditures to adapt to technological change.

We operate businesses that require sophisticated data collection, processing systems, software and other technology. Some of the technologies supporting the industries we serve are changing rapidly and increasing in complexity. New technologies will emerge or grow that may be superior to, or may not be compatible with, some of our existing technologies, and may require us to make significant investments and expenditures so that we can continue to provide cost-effective and reliable methods for energy production and delivery. Among such technological advances are distributed generation resources (e.g., private solar, microturbines, fuel cells), energy storage devices and more energy-efficient buildings and products designed to reduce energy consumption and waste. As these technologies become a more cost-competitive option over time, whether through cost effectiveness or government incentives and subsidies, such as under the IRA, certain customers formay choose to meet their own energy needs and subsequently decrease usage of our systems and services, including Indiana Electric’s generating facilities becoming less competitive and economical. Further, certain regulatory and legislative bodies have introduced or are considering requirements and/or incentives to reduce energy consumption by certain dates. Just as high inflation and rising interest rates, incentivize our customers to consume less energy, technological advances driven by federal laws mandating new levels of energy efficiency in end-use electric and natural gas devices or other improvements in or applications of technology could lead to declines in per capita energy consumption.

Our future success will depend, in part, on our ability to anticipate and adapt to these technological changes in a cost-effective manner, to offer, on a timely basis, reliable services that meet customer demands and evolving industry standards, and to recover all, or a significant portion of, its gathering and processing revenues and its transportation and storage revenues. The loss of,any unrecovered investment in obsolete assets. If we fail to adapt successfully to any technological change or reductionobsolescence, fail to obtain access to important technologies or incur significant expenditures in volumes from, these customers could result in a decline in sales of its gathering and processingadapting to technological change, or transportation and storage services and adversely affect itsif implemented technology does not operate as anticipated, our businesses, financial position,condition, results of operations and ability to make cash distributions.

For the year ended December 31, 2017, 57% of Enable’s gathered natural gas volumes were attributable to the affiliates of Continental, Vine, GeoSouthern, XTO Energy and Tapstone Energy and 51% of its transportation and storage service revenues were attributable to our affiliates or affiliates of Spire, American Electric Power Company, OGE and Continental. The loss of all or even a portion of the gathering and processing or transportation and storage services for any of these customers, the failure to extend or replace these contracts or the extension or replacement of these contracts on less favorable terms, as a result of competition or otherwise, could adversely affect Enable’s financial position, results of operations and ability to make cash distributions.

Enable’s businesses are dependent, in part, on the drilling and production decisions of others.

Enable’s businesses are dependent on the drilling and production of natural gas and crude oil. Enable has no control over the level of drilling activity in its areas of operation, or the amount of natural gas, NGL or crude oil reserves associated with wells connected to its systems. In addition, as the rate at which production from wells currently connected to its systems naturally declines over time, Enable’s gross margin associated with those wells will also decline. To maintain or increase throughput levels on its gathering and transportation systems and the asset utilization rates at its natural gas processing plants, Enable’s customers must continually obtain new natural gas, NGL and crude oil supplies. The primary factors affecting Enable’s ability to obtain new supplies of natural gas, NGLs and crude oil and attract new customers to its assets are the level of successful drilling activity near its systems, its ability to compete for volumes from successful new wells and its ability to expand its capacity as needed. If Enable is not able to obtain new supplies of natural gas, NGLs and crude oil to replace the natural decline in volumes from existing wells, throughput on its gathering, processing, transportation and storage facilities would decline, which could adversely affect its financial position, results of operations and ability to make cash distributions. Enable has no control over producers or their drilling and production decisions, which are affected by, among other things:

the availability and cost of capital;

prevailing and projected commodity prices, including the prices of natural gas, NGLs and crude oil;

demand for natural gas, NGLs and crude oil;

levels of reserves;

geological considerations;

environmental or other governmental regulations, including the availability of drilling permits and the regulation of hydraulic fracturing; and

the availability of drilling rigs and other costs of production and equipment.

Fluctuations in energy prices can also greatly affect the development of new natural gas, NGL and crude oil reserves. Drilling and production activity generally decreases as commodity prices decrease. In general terms, the prices of natural gas, NGLs, crude oil and other hydrocarbon products fluctuate in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond Enable’s control. Because of these and other factors, even if new reserves are known to exist in areas served by Enable’s assets, producers may choose not to develop those reserves. Declines in natural gas, NGL or crude oil prices can have a negative impact on exploration, development and production activity and, if sustained, could lead to decreases in such activity. Sustained low natural gas, NGL or crude oil prices could also lead producers to shut in production from their existing wells. Sustained reductions in exploration or production activity in Enable’s areas of operation could lead to further reductions in the utilization of its systems, which could adversely affect Enable’s financial position, results of operations and ability to make cash distributions.



In addition, it may be more difficult to maintain or increase the current volumes on Enable’s gathering systems and in its processing plants, as several of the formations in the unconventional resource plays in which it operates generally have higher initial production rates and steeper production decline curves than wells in more conventional basins. Should Enable determine that the economics of its gathering assets do not justify the capital expenditures needed to grow or maintain volumes associated therewith, Enable may reduce such capital expenditures, which could cause revenues associated with these assets to decline over time.

Enable’s industry is highly competitive, and increased competitive pressure could adversely affect its financial position, results of operations and ability to make cash distributions.

Enable competes with similar enterprises in its respective areas of operation. The principal elements of competition are rates, terms of service and flexibility and reliability of service. Enable’s competitors include large energy companies that have greater financial resources and access to supplies of natural gas, NGLs and crude oil than Enable. Some of these competitors may expand or construct gathering, processing, transportation and storage systems that would create additional competition for the services Enable provides to its customers. Excess pipeline capacity in the regions served by Enable’s interstate pipelines could also increase competition and adversely impact Enable’s ability to renew or enter into new contracts with respect to its available capacity when existing contracts expire. In addition, Enable’s customers that are significant producers of natural gas or crude oil may develop their own gathering, processing, transportation and storage systems in lieu of using Enable’s systems. Enable’s ability to renew or replace existing contracts with its customers at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of its competitors and customers. Further, natural gas utilized as a fuel competes with other forms of energy available to end users, including electricity, coal and liquid fuels. Increased demand for such forms of energy at the expense of natural gas could lead to a reduction in demand for natural gas gathering, processing, transportation and storage services. All of these competitive pressures could adversely affect Enable’s financial position, results of operations and ability to make cash distributions.affected.    

Enable may not be able to recover the costs of its substantial planned investment in capital improvements and additions, and the actual cost of such improvements and additions may be significantly higher than it anticipates.

Enable’s business plan calls for investment in capital improvements and additions. In Enable’s Form 10-K for the year ended December 31, 2017, Enable stated that it expects that its expansion capital could range from approximately $450 million to $600 million and its maintenance capital could range from approximately $95 million to $125 million for the year ending December 31, 2018.

The construction of additions or modifications to Enable’s existing systems, and the construction of new midstream assets, involves numerous regulatory, environmental, political and legal uncertainties, many of which are beyond Enable’s control and may require the expenditure of significant amounts of capital, which may exceed its estimates. These projects may not be completed at the planned cost, on schedule or at all. The construction of new pipeline, gathering, treating, processing, compression or other facilities is subject to construction cost overruns due to labor costs, costs and availability of equipment and materials such as steel, labor shortages or weather or other delays, inflation or other factors, which could be material. In addition, the construction of these facilities is typically subject to the receipt of approvals and permits from various regulatory agencies. Those agencies may not approve the projects in a timely manner, if at all, or may impose restrictions or conditions on the projects that could potentially prevent a project from proceeding, lengthen its expected completion schedule and/or increase its anticipated cost. Moreover, Enable’s revenues and cash flows may not increase immediately upon the expenditure of funds on a particular project. For instance, if Enable expands an existing pipeline or constructs a new pipeline, the construction may occur over an extended period of time, and Enable may not receive any material increases in revenues or cash flows until the project is completed. In addition, Enable may construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize. As a result, the new facilities may not be able to achieve Enable’s expected investment return, which could adversely affect its financial position, results of operations and ability to make cash distributions.

In connection with Enable’s capital investments, Enable may estimate, or engage a third party to estimate, potential reserves in areas to be developed prior to constructing facilities in those areas. To the extent Enable relies on estimates of future production in deciding to construct additions to its systems, those estimates may prove to be inaccurate either in volume or timing due to numerous uncertainties inherent in estimating future production. To the extent estimates of the volume of new production are inaccurate, new facilities may not be able to attract sufficient throughput to achieve expected investment return, which could adversely affect Enable’s financial position, results of operations and ability to make cash distributions. To the extent estimates in the timing of new production are inaccurate, new facilities may be constructed in advance of the actual need for capacity or may not be constructed in time to accommodate volume flows, which could adversely affect Enable’s financial position, results of operations and ability to make cash distributions. In addition, the construction of additions to existing gathering and transportation assets may require new rights-of-way prior to construction. Those rights-of-way to connect new natural gas supplies to existing


gathering lines may be unavailable and Enable may not be able to capitalize on attractive expansion opportunities. Additionally, it may become more expensive to obtain new rights-of-way or to renew existing rights-of-way. If the cost of renewing or obtaining new rights-of-way increases, Enable’s financial position, results of operations and ability to make cash distributions could be adversely affected.

Natural gas, NGL and crude oil prices are volatile, and changes in these prices could adversely affect Enable’s financial position, results of operations and ability to make cash distributions.

Enable’s financial position, results of operations and ability to make cash distributions could be negatively affected by adverse changes in the prices of natural gas, NGLs and crude oil depending on factors that are beyond Enable’s control. These factors include demand for these commodities, which fluctuates with changes in market and economic conditions and other factors, including the impact of seasonality and weather, general economic conditions, the level of domestic and offshore natural gas production and consumption, the availability of imported natural gas, LNG, NGLs and crude oil, actions taken by foreign natural gas and oil producing nations, the availability of local, intrastate and interstate transportation systems, the availability and marketing of competitive fuels, the impact of energy conservation efforts, technological advances affecting energy consumption and the extent of governmental regulation and taxation.

Enable’s natural gas processing arrangements expose it to commodity price fluctuations. In 2017, 7%, 35% and 58% of Enable’s processing plant inlet volumes consisted of keep-whole arrangements, percent-of-proceeds or percent-of-liquids and fee-based, respectively. If the price at which Enable sells natural gas or NGLs is less than the cost at which Enable purchases natural gas or NGLs under these arrangements, then Enable’s financial position, results of operations and ability to make cash distributions could be adversely affected.

At any given time, Enable’s overall portfolio of processing contracts may reflect a net short position in natural gas (meaning that Enable is a net buyer of natural gas) and a net long position in NGLs (meaning that Enable is a net seller of NGLs). As a result, Enable’s financial position, results of operations and ability to make cash distributions could be adversely affected to the extent the price of NGLs decreases in relation to the price of natural gas.

Enable is exposed to credit risks of its customers, and any material nonpayment or nonperformance by its customers could adversely affect its financial position, results of operations and ability to make cash distributions.

Some of Enable’s customers may experience financial problems that could have a significant effect on their creditworthiness. Severe financial problems encountered by its customers could limit Enable’s ability to collect amounts owed to it, or to enforce performance of obligations under contractual arrangements. In addition, many of Enable’s customers finance their activities through cash flow from operations, the incurrence of debt or the issuance of equity. The combination of reduction of cash flow resulting from declines in commodity prices, a reduction in borrowing bases under reserve-based credit facility and the lack of availability of debt or equity financing may result in a significant reduction of its customers’ liquidity and limit their ability to make payment or perform on their obligations to Enable. Furthermore, some of Enable’s customers may be highly leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to Enable. Financial problems experienced by Enable’s customers could result in the impairment of its assets, reduction of its operating cash flows and may also reduce or curtail their future use of its products and services, which could reduce Enable’s revenues.

Enable provides certain transportation and storage services under fixed-price “negotiated rate” contracts that are not subject to adjustment, even if its cost to perform such services exceeds the revenues received from such contracts, and, as a result, Enable’s costs could exceed its revenues received under such contracts.

Enable has been authorized by the FERC to provide transportation and storage services at its facilities at negotiated rates. As of December 31, 2017, approximately 44% of Enable’s aggregate contracted firm transportation capacity on EGT and MRT and 44% of its aggregate contracted firm storage capacity on EGT and MRT, was subscribed under such “negotiated rate” contracts. These contracts generally do not include provisions allowing for adjustment for increased costs due to inflation, pipeline safety activities or other factors that are not tied to an applicable tracking mechanism authorized by the FERC. Successful recovery of any shortfall of revenue, representing the difference between “recourse rates” (if higher) and negotiated rates, is not assured under current FERC policies. If Enable’s costs increase and it is not able to recover any shortfall of revenue associated with its negotiated rate contracts, the cash flow realized by Enable’s systems could decrease and, therefore, the cash Enable has available for distribution could also decrease.



If third-party pipelines and other facilities interconnected to Enable’s gathering, processing or transportation facilities become partially or fully unavailable for any reason, Enable’s financial position, results of operations and ability to make cash distributions could be adversely affected.

Enable depends upon third-party pipelines to deliver natural gas to, and take natural gas from, its natural gas transportation systems and upon third-party pipelines to take crude oil from its crude oil gathering systems. Enable also depends on third-party facilities to transport and fractionate NGLs that are delivered to the third party at the tailgates of Enable’s processing plants. Fractionation is the separation of the heterogeneous mixture of extracted NGLs into individual components for end-use sale. For example, an outage or disruption on certain pipelines or fractionators operated by a third party could result in the shutdown of certain of Enable’s processing plants and gathering systems, and a prolonged outage or disruption could ultimately result in a reduction in the volume of natural gas Enable gathers and NGLs it is able to produce. Additionally, Enable depends on third parties to provide electricity for compression at many of its facilities. Since Enable does not own or operate any of these third-party pipelines or other facilities, their continuing operation is not within its control. If any of these third-party pipelines or other facilities become partially or fully unavailable for any reason, Enable’s financial position, results of operations and ability to make cash distributions could be adversely affected.

Enable does not own all of the land on which its pipelines and facilities are located, which could disrupt its operations.

Enable does not own all of the land on which its pipelines and facilities have been constructed, and it is therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if it does not have valid rights-of-way or if such rights-of-way lapse or terminate. Enable may obtain the rights to construct and operate its pipelines for a specific period of time on lands owned by governmental agencies, American Indian tribes, or other third parties, including on American Indian allotments, title to which is held in trust by the United States. A loss of these rights, through Enable’s inability to renew right-of-way contracts or otherwise, could cause it to cease operations temporarily or permanently on the affected land, increase costs related to the construction and continuing operations elsewhere and adversely affect its financial position, results of operations and ability to make cash distributions.

Enable conducts a portion of its operations through joint ventures, which subject it to additional risks that could adversely affect the success of these operations and Enable’s financial position, results of operations and ability to make cash distributions.

Enable conducts a portion of its operations through joint ventures with third parties, including Spectra Energy Partners, LP, DCP Midstream, LP, Trans Louisiana Gas Pipeline, Inc. and Pablo Gathering LLC. Enable may also enter into other joint venture arrangements in the future. These third parties may have obligations that are important to the success of the joint venture, such as the obligation to pay their share of capital and other costs of the joint venture. The performance of these third-party obligations, including the ability of the third parties to satisfy their obligations under these arrangements, is outside Enable’s control. If these parties do not satisfy their obligations under these arrangements, Enable’s business may be adversely affected.

Enable’s joint venture arrangements may involve risks not otherwise present when operating assets directly, including, for example:

Enable’s joint venture partners may share certain approval rights over major decisions;

Enable’s joint venture partners may not pay their share of the joint venture’s obligations, leaving Enable liable for their shares of joint venture liabilities;

Enable may be unable to control the amount of cash it will receive from the joint venture;

Enable may incur liabilities as a result of an action taken by its joint venture partners;

Enable may be required to devote significant management time to the requirements of and matters relating to the joint ventures;

Enable’s insurance policies may not fully cover loss or damage incurred by both Enable and its joint venture partners in certain circumstances;

Enable’s joint venture partners may be in a position to take actions contrary to its instructions or requests or contrary to its policies or objectives; and

disputes between Enable and its joint venture partners may result in delays, litigation or operational impasses.



The risks described above or the failure to continue Enable’s joint ventures or to resolve disagreements with its joint venture partners could adversely affect its ability to transact the business that is the subject of such joint venture, which would in turn adversely affect Enable’s financial position, results of operations and ability to make cash distributions. The agreements under which Enable formed certain joint ventures may subject it to various risks, limit the actions it may take with respect to the assets subject to the joint venture and require Enable to grant rights to its joint venture partners that could limit its ability to benefit fully from future positive developments. Some joint ventures require Enable to make significant capital expenditures. If Enable does not timely meet its financial commitments or otherwise does not comply with its joint venture agreements, its rights to participate, exercise operator rights or otherwise influence or benefit from the joint venture may be adversely affected. Certain of Enable’s joint venture partners may have substantially greater financial resources than Enable has and Enable may not be able to secure the funding necessary to participate in operations its joint venture partners propose, thereby reducing its ability to benefit from the joint venture.

Under certain circumstances, Spectra Energy Partners, LP could have the right to purchase Enable’s ownership interest in SESH at fair market value.

Enable owns a 50% ownership interest in SESH. The remaining 50% ownership interest is held by Spectra Energy Partners, LP. We own 54.1% of Enable’s common units, 100% of its Series A Preferred Units and a 40% economic interest in Enable’s general partner. Pursuant to the terms of the limited liability company agreement of SESH, as amended, if, at any time, we have a right to receive less than 50% of Enable’s distributions through our interests in Enable and its general partner, or do not have the ability to exercise certain control rights, Spectra Energy Partners, LP could have the right to purchase Enable’s interest in SESH at fair market value, subject to certain exceptions.

Enable’s ability to grow is dependent on its ability to access external financing sources.

Enable expects that it will distribute all of its “available cash” to its unitholders. As a result, Enable is expected to rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund acquisitions and expansion capital expenditures. As a result, to the extent Enable is unable to finance growth externally, Enable’s cash distribution policy will significantly impair its ability to grow. In addition, because Enable is expected to distribute all of its available cash, its growth may not be as fast as businesses that reinvest their available cash to expand ongoing operations.

To the extent Enable issues additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that Enable will be unable to maintain or increase its per unit distribution level, which in turn may impact the available cash that it has to distribute on each unit. There are no limitations in Enable’s partnership agreement on its ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt by Enable to finance its growth strategy would result in increased interest expense, which in turn may negatively impact the available cash that Enable has to distribute to its unitholders.

Enable depends on access to the capital markets to fund its expansion capital expenditures. Historically, unit prices of midstream master limited partnerships have experienced periods of volatility. In addition, because Enable’s common units are yield-based securities, rising market interest rates could impact the relative attractiveness of its common units to investors. As a result of capital market volatility, Enable may be unable to issue equity or debt on satisfactory terms, or at all, which may limit its ability to expand its operations or make future acquisitions.

Enable’s debt levels may limit its flexibility in obtaining additional financing and in pursuing other business opportunities.

As of December 31, 2017, Enable had approximately $2.6 billion of long-term debt outstanding, excluding the premiums on their senior notes, $405 million outstanding under its commercial paper program and $450 million outstanding under its unsecured term loan agreement dated July 31, 2015. Enable has a $1.75 billion revolving credit facility for working capital, capital expenditures and other partnership purposes, including acquisitions, of which $1.3 billion was available as of February 1, 2018. Enable has the ability to incur additional debt, subject to limitations in its credit facilities. The levels of Enable’s debt could have important consequences, including the following:

the ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or the financing may not be available on favorable terms, if at all;

a portion of cash flows will be required to make interest payments on the debt, reducing the funds that would otherwise be available for operations, future business opportunities and distributions;



Enable’s debt level will make it more vulnerable to competitive pressures or a downturn in its business or the economy generally; and

Enable’s debt level may limit its flexibility in responding to changing business and economic conditions.

Enable’s ability to service its debt will depend upon, among other things, its future financial and operating performance, which will be affected by prevailing economic conditions, commodity prices and financial, business, regulatory and other factors, some of which are beyond Enable’s control. If operating results are not sufficient to service current or future indebtedness, Enable may be forced to take actions such as reducing distributions, reducing or delaying business activities, acquisitions, investments or capital expenditures, selling assets, restructuring or refinancing debt, or seeking additional equity capital. These actions may not be effected on satisfactory terms, or at all.

Enable’s credit facilities contain operating and financial restrictions, including covenants and restrictions that may be affected by events beyond Enable’s control, which could adversely affect its financial condition, results of operations and ability to make distributions.

Enable’s credit facilities contain customary covenants that, among other things, limit its ability to:

permit its subsidiaries to incur or guarantee additional debt;

incur or permit to exist certain liens on assets;

dispose of assets;

merge or consolidate with another company or engage in a change of control;

enter into transactions with affiliates on non-arm’s length terms; and

change the nature of its business.

Enable’s credit facilities also require it to maintain certain financial ratios. Enable’s ability to meet those financial ratios can be affected by events beyond its control, and we cannot assure you that it will meet those ratios. In addition, Enable’s credit facilities contain events of default customary for agreements of this nature.

Enable’s ability to comply with the covenants and restrictions contained in its credit facilities may be affected by events beyond its control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, Enable’s ability to comply with these covenants may be impaired. If Enable violates any of the restrictions, covenants, ratios or tests in its credit facilities, a significant portion of its indebtedness may become immediately due and payable. In addition, Enable’s lenders’ commitments to make further loans to it under the revolving credit facility may be suspended or terminated. Enable might not have, or be able to obtain, sufficient funds to make these accelerated payments.

Enable may be unable to obtain or renew permits necessary for its operations, which could inhibit its ability to do business.

Performance of Enable’s operations requires that Enable obtain and maintain a number of federal and state permits, licenses and approvals with terms and conditions containing a significant number of prescriptive limits and performance standards in order to operate. All of these permits, licenses, approval limits and standards require a significant amount of monitoring, record keeping and reporting in order to demonstrate compliance with the underlying permit, license, approval limit or standard. Noncompliance or incomplete documentation of Enable’s compliance status may result in the imposition of fines, penalties and injunctive relief. A decision by a government agency to deny or delay the issuance of a new or existing material permit or other approval, or to revoke or substantially modify an existing permit or other approval, could adversely affect Enable’s ability to initiate or continue operations at the affected location or facility and on its financial condition, results of operations and ability to make cash distributions.

Additionally, in order to obtain permits and renewals of permits and other approvals in the future, Enable may be required to prepare and present data to governmental authorities pertaining to the potential adverse impact that any proposed pipeline or processing-related activities may have on the environment, individually or in the aggregate, including on public and Indian lands. Certain approval procedures may require preparation of archaeological surveys, endangered species studies and other studies to assess the environmental impact of new sites or the expansion of existing sites. Compliance with these regulatory requirements is expensive and significantly lengthens the time required to prepare applications and to receive authorizations.



Costs of compliance with existing environmental laws and regulations are significant, and the cost of compliance with future environmental laws and regulations may adversely affect Enable’s financial position, results of operations and ability to make cash distributions.

Enable is subject to extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, waste management, wildlife conservation, natural resources and health and safety that could, among other things, delay or increase its costs of construction, restrict or limit the output of certain facilities and/or require additional pollution control equipment and otherwise increase costs. For instance, in May 2016, the EPA issued final New Source Performance Standards governing methane emissions imposing more stringent controls on methane and volatile organic compounds emissions at new and modified oil and natural gas production, processing, storage, and transmission facilities. These rules have required changes to Enable’s operations, including the installation of new equipment to control emissions. Additionally, several states are pursuing similar measures to regulate emissions of methane from new and existing sources. There are significant capital, operating and other costs associated with compliance with these environmental statutes, rules and regulations. Future federal and state regulations relating to Enable’s gathering and processing, transmission, and storage operations remain a possibility and could result in increased compliance costs on its operations. Furthermore, if new or more stringent federal, state or local legal restrictions are adopted in areas where its oil and natural gas exploration and production customers operate, they could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells, some or all of which could adversely affect demand for Enable’s services to those customers.

There is inherent risk of the incurrence of environmental costs and liabilities in Enable’s operations due to its handling of natural gas, NGLs, crude oil and produced water, as well as air emissions related to its operations and historical industry operations and waste disposal practices. These matters are subject to stringent and complex federal, state and local laws and regulations governing environmental protection, including the discharge of materials into the environment and the protection of plants, wildlife, and natural and cultural resources. These laws and regulations can restrict or impact Enable’s business activities in many ways, such as restricting the way it can handle or dispose of wastes or requiring remedial action to mitigate pollution conditions that may be caused by its operations or that are attributable to former operators. Joint and several strict liability may be incurred, without regard to fault, under certain of these environmental laws and regulations in connection with discharges or releases of wastes on, under or from Enable’s properties and facilities, many of which have been used for midstream activities for a number of years, oftentimes by third parties not under its control. Private parties, including the owners of the properties through which Enable’s gathering and transportation systems pass and facilities where its wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance, as well as to seek damages for non-compliance, with environmental laws and regulations or for personal injury or property damage. For example, an accidental release from one of Enable’s pipelines could subject it to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations. Enable may be unable to recover these costs from insurance. Moreover, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase compliance costs and the cost of any remediation that may become necessary. Further, stricter requirements could negatively impact Enable’s customers’ production and operations, resulting in less demand for its services.

Increased regulation of hydraulic fracturing and waste water injection wells could result in reductions or delays in natural gas production by Enable’s customers, which could adversely affect its financial position, results of operations and ability to make cash distributions.

Hydraulic fracturing is common practice that is used by many of Enable’s customers to stimulate production of natural gas and crude oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand, and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing typically is regulated by state oil and natural gas commissions. In addition, certain federal agencies have proposed additional laws and regulations to more closely regulate the hydraulic fracturing process. In past sessions, Congress has considered, but not passed, legislation to provide for federal regulation of hydraulic fracturing under the Safe Drinking Water Act and to require disclosure of the chemicals used in the hydraulic fracturing process. The EPA has issued the Safe Water Drinking Act permitting guidance for hydraulic fracturing operations involving the use of diesel fuel in fracturing fluids in those states where the EPA is the permitting authority.

Some states have adopted, and other states have considered adopting, legal requirements that could impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing activities. Local government also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular, in some cases banning hydraulic fracturing entirely. If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where Enable’s oil and natural gas exploration


and production customers operate, they could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells, some or all of which activities could adversely affect demand for Enable’s services to those customers.

State and federal regulatory agencies recently have focused on a possible connection between the operation of injection wells used for oil and gas waste disposal and seismic activity. Similar concerns have been raised that hydraulic fracturing may also contribute to seismic activity. When caused by human activity, such events are called induced seismicity. In March 2016, the United States Geological Survey identified six states with the most significant hazards from induced seismicity, including Oklahoma, Kansas, Texas, Colorado, New Mexico, and Arkansas. In March 2017, the United States Geological Survey produced an updated seismic hazard survey that forecasted lower earthquake rates in regions of induced activity, but still showed significantly elevated hazards in the central and eastern United States. In light of these concerns, some state regulatory agencies have modified their regulations or issued orders to address induced seismicity. For example, the OCC has implemented volume reduction plans, and at times required shut-ins, for disposal wells injecting wastewater from oil and gas operations into the Arbuckle formation. In December 2016, the OCC also released well completion seismicity guidelines for operators in the South Central Oklahoma Oil Province and the Sooner Trend Anadarko Basin Canadian and Kingfisher Counties that call for hydraulic fracturing operations to be suspended following earthquakes of certain magnitudes in the vicinity. Certain environmental and other groups have also suggested that additional federal, state and local laws and regulations may be needed to more closely regulate the hydraulic fracturing process. Enable cannot predict whether additional federal, state or local laws or regulations applicable to hydraulic fracturing will be enacted in the future and, if so, what actions any such laws or regulations would require or prohibit. Increased regulation and attention given to induced seismicity could lead to greater opposition to, and litigation concerning, oil and gas activities utilizing hydraulic fracturing or injection wells for waste disposal. Additional legislation or regulation could also lead to operational delays or increased operating costs for Enable’s customers, which in turn could reduce the demand for Enable’s services.

Other governmental agencies, including the DOE, have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the Safe Drinking Water Act or other regulatory mechanisms.

Enable’s operations are subject to extensive regulation by federal, state and local regulatory authorities. Changes or additional regulatory measures adopted by such authorities could adversely affect Enable’s financial position, results of operations and ability to make cash distributions.

The rates charged by several of Enable’s pipeline systems, including for interstate gas transportation service provided by its intrastate pipelines, are regulated by the FERC. Enable’s pipeline operations that are not regulated by the FERC may be subject to state and local regulation applicable to intrastate natural gas transportation services and crude oil gathering services. The relevant states in which Enable operates include North Dakota, Oklahoma, Arkansas, Louisiana, Texas, Missouri, Kansas, Mississippi, Tennessee and Illinois.

The FERC and state regulatory agencies also regulate other terms and conditions of the services Enable may offer. If one of these regulatory agencies, on its own initiative or due to challenges by third parties, were to lower its tariff rates or deny any rate increase or other material changes to the types, or terms and conditions, of service Enable might propose or offer, the profitability of Enable’s pipeline businesses could suffer. If Enable were permitted to raise its tariff rates for a particular pipeline, there might be significant delay between the time the tariff rate increase is approved and the time that the rate increase actually goes into effect, which could also limit its profitability. Furthermore, competition from other pipeline systems may prevent Enable from raising its tariff rates even if regulatory agencies permit it to do so. The regulatory agencies that regulate Enable’s systems periodically implement new rules, regulations and terms and conditions of services subject to their jurisdiction. New initiatives or orders may adversely affect the rates charged for Enable’s services or otherwise adversely affect its financial position, results of operations and cash flows and ability to make cash distributions. Further, should Enable fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, it could be subject to substantial penalties and fines.

A change in the jurisdictional characterization of some of Enable’s assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of its assets, which may cause its revenues to decline and operating expenses to increase.

Enable’s natural gas gathering and intrastate transportation operations are generally exempt from the jurisdiction of the FERC under the NGA, but FERC regulation may indirectly impact these businesses and the markets for products derived from these businesses. The FERC’s policies and practices across the range of its oil and natural gas regulatory activities, including, for example, its policies on interstate open access transportation, ratemaking, capacity release, and market center promotion may indirectly affect intrastate markets. In recent years, the FERC has pursued pro-competitive policies in its regulation of interstate oil and


natural gas pipelines. However, we cannot assure you that the FERC will continue to pursue this approach as it considers matters such as pipeline rates and rules and policies that may indirectly affect the intrastate natural gas transportation business. Although the FERC has not made a formal determination with respect to all of Enable’s facilities it considers to be gathering facilities, Enable believes that its natural gas gathering pipelines meet the traditional tests that the FERC has used to determine that a pipeline is a gathering pipeline and are therefore not subject to FERC jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services, however, has been the subject of substantial litigation, and the FERC determines whether facilities are gathering facilities on a case-by-case basis, so the classification and regulation of Enable’s gathering facilities is subject to change based on future determinations by the FERC, the courts or Congress. If the FERC were to consider the status of an individual facility and determine that the facility and/or services provided by it are not exempt from FERC regulation under the NGA and that the facility provides interstate service, the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by the FERC under the NGA or the NGPA. Such regulation could decrease revenue, increase operating costs, and, depending upon the facility in question, could adversely affect Enable’s financial condition, results of operations and ability to make cash distributions. In addition, if any of Enable’s facilities were found to have provided services or otherwise operated in violation of the NGA or the NGPA, this could result in the imposition of substantial civil penalties, as well as a requirement to disgorge revenues collected for such services in excess of the maximum rates established by the FERC.

Natural gas gathering may receive greater regulatory scrutiny at the state level; therefore, Enable’s natural gas gathering operations could be adversely affected should they become subject to the application of state regulation of rates and services. Enable’s gathering operations could also be subject to safety and operational regulations relating to the design, construction, testing, operation, replacement and maintenance of gathering facilities. We cannot predict what effect, if any, such changes might have on Enable’s operations, but Enable could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

Other Risk Factors Affecting Our Businesses or Our Interests in Enable Midstream Partners, LP

We are subject to operational and financial risks and liabilities arising from environmental laws and regulations.

Our operations and the operations of Enable are subject to stringent and complex laws and regulations pertaining to the environment. As an owner or operator of natural gas pipelines, distribution systems and storage, electric transmission and distribution systems, and the facilities that support these systems, we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as:

restricting the way we can handle or dispose of wastes;

limiting or prohibiting construction activities in sensitive areas such as wetlands, coastal regions, or areas inhabited by endangered species;

requiring remedial action to mitigate environmental conditions caused by our operations, or attributable to former operations;

enjoining the operations of facilities with permits issued pursuant to such environmental laws and regulations; and

impacting the demand for our services by directly or indirectly affecting the use or price of natural gas.

To comply with these requirements, we may need to spend substantial amounts and devote other resources from time to time to:

construct or acquire new facilities and equipment;

acquire permits for facility operations;

modify or replace existing and proposed equipment; and

clean or decommission waste management areas, fuel storage facilities and other locations.

Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial actions, and the issuance of orders enjoining future operations. Certain environmental statutes impose strict joint and several liability for costs required to clean and restore sites where hazardous substances have been stored, disposed or released. Moreover, it is not uncommon for neighboring landowners


and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other waste products into the environment.

The recent trend in environmental regulation has been to place more restrictions and limitations on activities that may impact the environment, and thus there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be greater than the amounts we currently anticipate.


Our insurance coverage may not be sufficient. Insufficient insurance coverage and increased insurance costs could adversely impact our financial condition, results of operations financial condition and cash flows.


We currently have insurance in place, such as general liability and property insurance, in place to cover certain of our facilities in amounts that we consider appropriate. Such policies are subject to certain limits and deductibles and do not include business interruption coverage. Insurance coverage premiums continue to increase, and insurance coverage may not be available in the future at current costs or on commercially reasonable terms, and the insurance proceeds received for any loss of, or any damage to, any of our facilities may not be sufficient to fully cover or restore the loss or damage without negative impact on our financial condition, results of operations financial condition and cash flows. Costs, damages and other liabilities related to recent events and incidents that affected other utilities, such as wildfires, winter storms and explosions, among other things, have exceeded or could exceed such utilities’ insurance coverage. Further, as a result of these recent events and incidents, the marketplace for insurance coverage to utility companies may be unavailable or limited in capacity or any such available coverage may be deemed by us to be cost prohibitive under current conditions. Insurance premiums for any such coverage, if available, may not be eligible for recovery, whether in full or in part, by us through the rates charged by our utility businesses.


In common with other companies in its line of business that serve coastal regions, Houston Electric does not have insurance covering its transmission and distribution system, other than substations, because Houston Electric believes it to be cost prohibitive and believes insurance capacity to be limited. In the future,Historically, Houston Electric may not behas been able to recover the costs incurred in restoring its transmission and distribution properties following hurricanes or other disasters through issuance of storm restoration bonds or a change in its regulated rates or otherwise, orotherwise. In the future, any such recovery may not be timely granted. Therefore, Houston Electric may not be able to restore any loss of, or damage to, any of its transmission and distribution properties without negative impact on its financial condition, results of operations and cash flows.

Global or regional health pandemics, epidemics or similar public health threats could negatively impact our business, outlook, financial condition, results of operations and liquidity.

Current and future health pandemics, epidemics and similar public health threats, such as COVID-19 and its variants, and the measures implemented to contain their spread, such as travel bans and restrictions, quarantines and vaccination mandates, continue to and may in the future have widespread impacts on the global economy, our employees, customers, and third-party business partners. The severity, magnitude and duration of a current or future health threatis uncertain, rapidly changing and hard to predict. Any future health threat, including the emergence of a new variant of COVID-19, could, in the future, impact our business in numerous ways, including, but not limited to, those outlined below:

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•reduced demand from our commercial and industrial customers and shifts in demand for our services;
•delayed service to customers because of shutdowns and/or illness and travel restrictions among our employees;
•negative impacts to the financial condition of our customers and REPs and their ability to pay for our services, and our ability to disconnect service for non-payment may be limited, and state regulators may impose bill deferral programs;
•potential limits or significant or entire curtailments of the ability of public utility commissions to approve or authorize applications and other requests we may make with respect to our businesses, including delaying rate making proceedings;
•increased risk to our cybersecurity program as a result of an increase in cyberattacks during the pandemic and increased remote working arrangements, see above “Risks Affecting our Safety and Security Risks”;
•increased rates of inflation and delays in our supply chain and our ability to complete maintenance, repairs, and capital programs, which could result in disruption, increased costs and our inability to execute on or require us to make modifications to our capital plan; and
•accelerated employee turnover as a result of concerns regarding restrictions and guidelines, including mask mandates and quarantine mandates, and increased acceptability of alternative work arrangements.

Like many companies, we experienced the above and other impacts pursuant to the COVID-19 pandemic.These and other impacts of global or regional health pandemics, epidemics or similar public health threats could also have the effect of heightening many of the other risks described in this section and the other reports we file from time to time with the SEC. We might not be able to predict or respond to all impacts on a timely basis to prevent near- or long-term adverse impacts to our operations, financial condition and cash flows.

Our operationsliquidity. The ultimate impact of public health threats on our business depends on factors beyond our knowledge or control, including the duration and Enable’s operations are subject to allseverity of the risksoutbreak as well as third-party actions taken to contain the spread and hazards inherent inmitigate the gathering, processing, transportation and storagepublic health effects. Any of natural gas and crude oil, including:

damage to pipelines and plants, related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires, earthquakes and other natural disasters, acts of terrorism and actions by third parties;

inadvertent damage from construction, vehicles, farm and utility equipment;

leaks of natural gas, NGLs, crude oil and other hydrocarbons or losses of natural gas, NGLs and crude oil as a result of the malfunction of equipment or facilities;

ruptures, fires and explosions; and

other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.

These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property, plant and equipment and pollution or other environmental damage. These risks may also result in curtailment or suspension of our or Enable’s operations. A natural disaster or other hazard affecting the areas in which we or Enable operatethese factors could have a material adverse effect on our or Enable’s operations.

Enable is not fully insured against all risks inherent in its business. Enable currently has general liability and property insurance in place to cover certain of its facilities in amounts that Enable considers appropriate. Such policies are subject to certain limits and deductibles. Enable does not have business interruption insurance coverage for all of its operations. Insurance coverage may not be available in the future at current costs or on commercially reasonable terms, and the insurance proceeds received for any loss of, or any damage to, any of Enable’s facilities may not be sufficient to restore the loss or damage without negative impact on itsour business, outlook, financial condition and results of operations, and its ability to make cash distributions.which impact could be material.

We, Houston Electric and CERC could incur liabilities associated with businesses and assets that we have transferred to others.

Under some circumstances, we, Houston Electric and CERC could incur liabilities associated with assets and businesses we, Houston Electric and CERC no longer own. These assets and businesses were previously owned by Reliant Energy, a predecessor of Houston Electric, directly or through subsidiaries and include:



merchant energy, energy trading and REP businesses transferred to RRI or its subsidiaries in connection with the organization and capitalization of RRI prior to its initial public offering in 2001 and now owned by affiliates of NRG; and

Texas electric generating facilities transferred to a subsidiary of Texas Genco in 2002, later sold to a third party and now owned by an affiliate of NRG.

In connection with the organization and capitalization of RRI (now GenOn) and Texas Genco (now an affiliate of NRG), those companies and/or their subsidiaries assumed liabilities associated with various assets and businesses transferred to them and agreed to certain indemnity agreements of CenterPoint Energy entities. Such indemnities have applied in cases such as the litigation arising out of sales of natural gas in California and other markets (the last remaining case involving us is now on appeal, following the district court’s summary judgment in favor of CES, a subsidiary of CERC Corp.) and various asbestos and other environmental matters that arise from time to time. In June 2017, GenOn and various affiliates filed for protection under Chapter 11 of the U.S. Bankruptcy Code. In December 2017, GenOn received court approval of a restructuring plan and is expected to emerge from Chapter 11 in mid-2018. We, CERC and CES submitted proofs of claim in the bankruptcy proceedings to protect our indemnity rights. If any of the indemnifying entities were unable to meet their indemnity obligations or satisfy a liability that has been assumed in the gas market manipulation litigation, we, Houston Electric or CERC could incur liability and be responsible for satisfying the liability.

In connection with our sale of Texas Genco, the separation agreement was amended to provide that Texas Genco would no longer be liable for, and we would assume and agree to indemnify Texas Genco against, liabilities that Texas Genco originally assumed in connection with its organization to the extent, and only to the extent, that such liabilities are covered by certain insurance policies held by us, and in certain of the asbestos lawsuits we have agreed to continue to defend such claims to the extent they are covered by insurance maintained by us, subject to reimbursement of the costs of such defense by an NRG affiliate.

Cyber-attacks, physical security breaches, acts of terrorism or other disruptions could adversely impact our or Enable’s reputation, results of operations, financial condition and/or cash flows.

We and Enable are subject to cyber and physical security risks related to adversaries attacking information technology systems, network infrastructure, technology and facilities used to conduct almost all of our and Enable’s business which includes (i) managing operations and other business processes and (ii) protecting sensitive information maintained in the normal course of business. For example, the operation of our electric transmission and distribution system is dependent on not only physical interconnection of our facilities but also on communications among the various components of our system. This reliance on information and communication between and among those components has increased since deployment of smart meters and the intelligent grid.  Similarly, our and Enable’s business operations are interconnected with external networks and facilities. The distribution of natural gas to our customers requires communications with Enable’s pipeline facilities and third-party systems. The gathering, processing and transportation of natural gas from Enable’s gathering, processing and pipeline facilities and crude oil gathering pipeline systems also rely on communications among its facilities and with third-party systems that may be delivering natural gas or crude oil into or receiving natural gas or crude oil and other products from Enable’s facilities. Disruption of those communications, whether caused by physical disruption such as storms or other natural disasters, by failure of equipment or technology or by manmade events, such as cyber-attacks or acts of terrorism, may disrupt our or Enable’s ability to conduct operations and control assets.

Cyber-attacks and unauthorized access could also result in the loss, or unauthorized use, of confidential, proprietary or critical infrastructure data or security breaches of other information technology systems that could disrupt operations and critical business functions, adversely affect reputation, increase costs and subject us or Enable to possible legal claims and liability. Further, third parties, including vendors, suppliers and contractors, who perform certain services for us or administer and maintain our sensitive information, could also be targets of cyber-attacks and unauthorized access. Neither we nor Enable is fully insured against all cyber-security risks, any of which could adversely affect our reputation and could have a material adverse effect on either our or Enable’s results of operations, financial condition and/or cash flows.

In addition, our and Enable’s critical energy infrastructure may be targets of terrorist activities that could disrupt our respective business operations. In January 2017, the DOE’s Quadrennial Energy Review reported that cyber threats to the electricity system are increasing in sophistication, magnitude and frequency. Any such disruptions could result in significant costs to repair damaged facilities and implement increased security measures, which could have a material adverse effect on either our or Enable’s results of operations, financial condition and/or cash flows.



Failure to maintain the security of personally identifiable information could adversely affect us.

In connection with our business we collect and retain personally identifiable information (e.g., information of our customers, shareholders, suppliers and employees), and there is an expectation that we will adequately protect that information. The U.S. regulatory environment surrounding information security and privacy is increasingly demanding. A significant theft, loss or fraudulent use of the personally identifiable information we maintain, or of our data, by cyber-crime or otherwise could adversely impact our reputation and could result in significant costs, fines and litigation.

Our results of operations, financial condition and cash flows may be adversely affected if we are unable to successfully operate our facilities or perform certain corporate functions.

Our performance depends on the successful operation of our facilities. Operating these facilities involves many risks, including:

operator error or failure of equipment or processes, including failure to follow appropriate safety protocols;

the handling of hazardous equipment or materials that could result in serious personal injury, loss of life and environmental and property damage;

operating limitations that may be imposed by environmental or other regulatory requirements;

labor disputes;

information technology or financial system failures, including those due to the implementation and integration of new technology, that impair our information technology infrastructure, reporting systems or disrupt normal business operations;

information technology failure that affects our ability to access customer information or causes us to lose confidential or proprietary data that materially and adversely affects our reputation or exposes us to legal claims; and
catastrophic events such as fires, earthquakes, explosions, leaks, floods, droughts, hurricanes, terrorism, pandemic health events or other similar occurrences, which may require participation in mutual assistance efforts by us or other utilities to assist in power restoration efforts.

Such events may result in a decrease or elimination of revenue from our facilities, an increase in the cost of operating our facilities or delays in cash collections, any of which could have a material adverse effect on our results of operations, financial condition and/or cash flows.


Our success depends upon our ability to attract, effectively transition, motivate and retain key employees and identify and develop talent to succeed senior management.


We depend on our senior executive officers and other key personnel. Our success depends on our ability to attract, effectively transition and retain key personnel. Further tightening of the labor market and increasing wages to attract and retain key personnel may adversely affect our ability to attract and retain key personnel. The inability to recruit and retain or effectively transition key personnel or the unexpected loss of key personnel may adversely affect our operations. In addition, because of the reliance on our management team, our future success depends in part on our ability to identify and develop talent to succeed senior management. The retention of key personnel and appropriate senior management succession planning will continue to be critically important to the successful implementation of our strategies.


Failure to attract and retain an appropriately qualified workforce and maintain good labor relations could adversely impact the operations of our facilities and our results of operations.


Our business isbusinesses are dependent on recruiting, retaining and motivating employees. Like many companies in the utilities industry and other industries, we have experienced higher than normal turnover of employees as a result of a number of factors, including the COVID-19 pandemic, a tightening labor market, increasing remote working opportunities, employees shifting industries, individuals deciding not to work and a maturing workforce. Of our abilityemployee population, not including employees of Energy Systems Group prior to recruit, retain,the divestiture on June 30, 2023 or temporary employees, 18.7%, 19.3% and motivate employees.23.6% were retirement eligible as of December 31, 2023, 2022 and 2021, respectively. Certain circumstances, such as an aging workforce without appropriate replacements, a mismatch of existing skillsets to future needs, or the unavailability of contract resources may lead to operating challenges such as a lack of resources, loss of knowledge or a lengthy time period associated with skill development. Our costs, including costs to replace employees, productivity costs and safety costs, may rise. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to the new employees, or the future availability and cost of contract labor may adversely affect the ability to manage and operate our business.businesses, particularly the specialized skills and knowledge required to construct and operate generation facilities, a technology-enabled power grid and transmission and distribution infrastructure, among other facilities. If we are unable to successfully attract and retain an appropriately qualified workforce, our ability to execute on our 10-year capital plan and our results of operations could be negatively affected.




Climate change legislation and regulatory initiatives could result in increased operating costs and reduced demand for our or Enable’s services.

Regulatory agencies have from time to time considered adopting legislation, including modification of existing laws and regulations, to reduce GHGs, and there continues to be a wide-ranging policy and regulatory debate, both nationally and internationally, regardingFurthermore, the potential impact of GHGs and possible means for their regulation.  Efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues.

Following a finding by the EPA that certain GHGs represent an endangerment to human health, the EPA adopted two sets of rules regulating GHG emissions under the Clean Air Act, one that requires a reduction in emissions of GHGs from motor vehicles and another that regulates emissions of GHGs from certain large stationary sources. The EPA has also expanded its existing GHG emissions reporting requirements. These permitting and reporting requirements could lead to further regulation of GHGs by the EPA. As a distributor and transporter of natural gas, or a consumer of natural gas in its pipeline and gathering businesses, CERC’s or Enable’s revenues, operating costs and capital requirements, as applicable, could be adversely affected as a result of any regulatory action that would require installation of new control technologies or a modification of its operations or would have the effect of reducing the consumption of natural gas.  Our electric transmission and distribution business, in contrast to some electric utilities, does not generate electricity 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 revenues could be adversely affected to the extent any resulting regulatory action has the effect of reducing consumption of electricity by ultimate consumers within its service territory. Likewise, incentives to conserve energy or use energy sources other than natural gas could result in a decrease in demand for our services.

Climate changes could adversely impact financial results from our and Enable’s businesses and result in more frequent and more severe weather events which could adversely affect the results of operations of our businesses.

If climate changes occur that result in warmer temperatures in our service territories, financial results from our and Enable’s businesses could be adversely impacted. For example, CERC’s NGD could be adversely affected through lower natural gas sales and Enable’s natural gas gathering, processing and transportation and crude oil gathering businesses could experience lower revenues. Another possible result of climate change is more frequent and more severe weather events, such as hurricanes or tornadoes.  Since many of our facilities are located along or near the Gulf Coast, increased or more severe hurricanes or tornadoes could increase our costs to repair damaged facilities and restore service to our customers.  When we cannot deliver electricity or natural gas to customers or our customers cannot receive our services, our financial results can be impacted by lost revenues, and we generally must seek approval from regulators to recover restoration costs.  To the extent we are unable to recover those costs, or if higher rates resulting from our recovery of such costs result in reduced demand for our services, our future financial results may be adversely impacted.

We are uncertain how state commissions and local municipalities may require us to respond to the effects of the recent comprehensive tax reform legislation, and these regulatory requirements may adversely affect our results of operations, financial condition and cash flows.

On December 22, 2017, President Trump signed into law comprehensive tax reform legislation informally called the Tax Cuts and Jobs Act, or TCJA, which resulted in significant changes to federal tax laws effective January 1, 2018, including, but not limited to, a reduction in the corporate income tax rate.

For Houston Electric and NGD, federal income tax expense is included in the rates approved by state commissions and local municipalities and charged by those utilities to consumers. When Houston Electric and NGD have general rate cases and other periodic rate adjustments, we expect the lower corporate tax expense resulting from the TCJA (which includes determining the treatment of EDIT), along with other increases and decreases in our revenue requirements, to be incorporated into Houston Electric’s and NGD’s future rates. Nevertheless, regulators may require us to respond to the TCJA in other ways, including through faster recoveries of reductions in federal income tax expense, accounting orders to reflect a liability to return to customers in future rate proceedings, accelerated returns to consumers of previously collected deferred federal income taxes, increased funding of infrastructure upgrades, or offsets of future rate increases. The effect on us of any potential return of tax savings resulting from the TCJA to consumers may differ depending on how each regulatory body requires us to return such savings.

On January 25, 2018, the PUCT issued an accounting order in Project No. 47945 directing electric utilities, including Houston Electric, to record as a regulatory liability (1) the difference between revenues collected under existing rates and revenues that would have been collected had the existing rates been set using the recently approved federal income tax rates and (2) the balance of EDIT that now exists because of the reduction in federal income tax rates. On February 13, 2018, Houston Electric and other


likely parties to a future rate case announced a settlement that requires Houston Electric to make (i) a TCOS filing by February 20, 2018 to reflect the change in the federal income tax rate for Houston Electric’s transmission rate base through July 31, 2017 and account for certain EDIT (and such filing was timely submitted), (ii) a DCRF filing in April 2018 to reflect the change in the federal income tax rate for Houston Electric’s distribution rate base through December 31, 2017 and (iii) a full rate case filing by April 30, 2019. The settlement was presented to the PUCT during its open meeting on February 15, 2018. In response to the settlement, the PUCT did not proceed with a prior proposal to require Houston Electric to file a rate case in the summer of 2018. The PUCT also amended its prior accounting order to remove the requirement that utilities include carrying costs in the new regulatory liability. 

We can provide no assurances on how any regulatory body will ultimately require us to act. As such, we are currently unable to determine the impact of these potential regulatory actions in response to the enactment of the TCJA, which may adversely affect our results of operations, financial condition and cash flows.

In addition, the TCJA also includes a variety of other changes, such as a limitation on the tax deductibility of interest expense and acceleration of business asset expensing, among others. Several provisions of the TCJA are not generally applicable to the public utility industry, including the limitation on the tax deductibility of interest expense and the acceleration of business asset expensing. We continue to assess the impact that the TCJA may have on our future results of operations, financial condition and cash flows, which impact may adversely affect our future results of operations, financial condition and cash flows.

CERC and Enable may incur significant costs and liabilities resulting from pipeline integrity and other similar programs and related repairs.

Certain of CERC’s and Enable’s pipeline operations are subject to pipeline safety laws and regulations. The DOT’s PHMSA has adopted regulations requiring pipeline operators to develop integrity management programs, including more frequent inspections and other measures, for transportation pipelines located in “high consequence areas,” which are those areas where a leak or rupture could do the most harm. The regulations require pipeline operators, including CERC and Enable, to, among other things:

perform ongoing assessments of pipeline integrity;

develop a baseline plan to prioritize the assessment of a covered pipeline segment;

identify and characterize applicable threats that could impact a high consequence area;

improve data collection, integration, and analysis;

develop processes for performance management, record keeping, management of change and communication;

repair and remediate pipelines as necessary; and

implement preventive and mitigating action.

Failure to comply with PHMSA or comparable state pipeline safety regulations could result in a number of consequences that may have an adverse effect on CERC’s and Enable’s operations. Both CERC and Enable incur significant costs associated with their compliance with existing PHMSA and comparable state regulations, which may not be recoverable in rates.

Changes to pipeline safety laws and regulations that result in more stringent or costly safety standards could have a significant adverse effect on CERC and Enable. For example, in January 2017, PHMSA announced the issuance of the Pipeline Safety: Safety of Hazardous Liquids Pipelines final rule.  The final rule extends regulatory reporting requirements to additional liquid gathering lines, requires additional event-driven and periodic inspections, requires use of leak detection systems on additional hazardous liquid pipelines, modifies repair criteria, and requires certain pipelines to eventually accommodate inline inspection tools. It is unclear when or if this rule will go into effect as, on January 20, 2017, the Trump Administration requested that all regulations that had been sent to the Office of the Federal Register, but not yet published, be immediately withdrawn for further review, which is currently in progress. These proposals, if finalized, would impose additional costs on CERC and Enable.

In March 2016, PHMSA issued a notice of proposed rulemaking detailing proposed revisions to the safety standards applicable to natural gas transmission and gathering pipelines. The proposed rules include significant modifications which, if adopted, will result in significant operational and integrity management changes. These include requiring reconfirmation of the Maximum Allowable Operating Pressures in pipelines without reliable records, creating new material verification procedures, adding a new


moderate consequence area, and tightening repair criteria for pipelines in both high and moderate consequence areas. Other modifications include adding record-keeping and data collection obligations, and new requirements for monitoring gas quality and managing corrosion. The proposed rules also would expand the scope of gas gathering lines subject to PHMSA regulation, including imposing minimum safety standards on certain larger, currently exempt, gathering lines, while subjecting all gathering-line operators to recordkeeping and annual reporting requirements from which they are currently exempt. Other proposed changes, such as the modification to the definition of a transmission line, some record-keeping requirements, and some material verification obligations also may impact distribution pipelines although PHMSA states that such far-reaching applicability is not its intent. This rule is also currently under evaluation, and PHMSA is expected to issue a final rule in the third quarter of 2018 at the earliest. Because the impact of these proposed rules remains uncertain, we are still monitoring and evaluating the effect of these proposed requirements on operations.

On December 14, 2016, PHMSA announced an interim final rule to impose industry-developed recommendations as enforceable safety standards for downhole (underground) equipment, including wells, wellbore tubing, and casing, at both interstate and intrastate underground natural gas storage facilities. States may also impose more stringent standards on intrastate storage facilities. Both CERC and Enable own and operate underground storage facilities that will be subject to this rule’s provisions, which include procedures and practices for operations, maintenance, threat identification, monitoring, assessment, site security, emergency response and preparedness, training and recordkeeping. Although not yet finalized, the interim rule went into effect on January 18, 2017, with a compliance deadline of January 18, 2018. PHMSA determined, however, that it will not issue enforcement citations to any operators for violations of those provisions of the interim final rule that had previously been non-mandatory provisions of American Petroleum Institute Recommended Practices 1170 and 1171 until one year after PHMSA issues a final rule, which has not yet been issued. This matter remains ongoing and subject to future PHMSA determinations. CERC and Enable will continue to monitor developments and assess the potential impact of any modifications to this rule.

Proposed rulemakings such as those discussed above could expand the scope of natural gas and hazardous liquids integrity management programs and other pipeline safety regulations to include additional requirements or previously exempt pipelines. CERC and Enable have not estimated the cost of complying with any proposed changes to the regulations administered by PHMSA or state pipeline safety regulators.

Aging infrastructure may lead to increased costs and disruptions in operations that could negatively impact our financial results.

We have risks associated with aging infrastructure assets.  The age of certain of our assets may result in a need for replacement, or higher level of maintenance costs as a result of our risk based federal and state compliant integrity management programs.  Failure to achieve timely recovery of these expenses could adversely impact revenues and could result in increased capital expenditures or expenses.

The operation of our facilities dependsdepend on good labor relations with our employees.

Severalemployees, and several of our businesses have entered into and have in place collective bargaining agreements with different labor unions. There are sevenunions, comprising approximately 40% of our workforce. We have several separate bargaining units, in CenterPoint Energy, each with a unique collective bargaining agreement. In 2017, CERC entered into renegotiatedagreement described further in
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Note 8(j) to the consolidated financial statements, which information is incorporated herein by reference. The collective bargaining agreements with United SteelworkersTeamsters Local 227135 related to SIGECO employees and United SteelworkersUtility Workers Union of America, Local 13-1, which175 related to VEDO employees are scheduled to expire in JuneSeptember 2024 and JulyOctober 2024, respectively, and negotiations of 2022, respectively. The collective bargainingthese agreements with Gas Workers Union Local 340, IBEW Local 66 and Local 949 are each scheduledexpected to expire in 2020, andbe completed before the collective bargaining agreements with Professional Employees International Union Local 12 are scheduled to expire in 2021.respective expirations. Any failure to reach an agreement on new labor contracts or to negotiate these labor contracts might result in strikes, boycotts or other labor disruptions. These potential labor disruptions could have a materialan adverse effect on our businesses, results of operations and/or cash flows. Labor disruptions, strikes or significant negotiated wage and benefit increases, whether due to union activities, employee turnover or otherwise, could have a materialan adverse effect on our businesses, results of operations and/orand cash flows.


Item 1B.Unresolved Staff Comments

None.

Item 1C.Cybersecurity

Our businesses willprocesses for assessing, identifying, and managing material risks from cybersecurity threats are part of our overall enterprise risk management system and processes. Enterprise risks, including cybersecurity risks, and their associated mitigations are reviewed at least annually by senior management and the Board of Directors. Throughout the year, we regularly assess our cybersecurity program and continue to invest in hardening and maturing our cybersecurity measures as further described below.

Managing Material Risks & Integrated Overall Risk Management

As a foundation of this approach, we have implemented a layered governance structure to adapthelp assess, identify, and manage cybersecurity risks. It starts with our internal Cybersecurity Operations Center (CSOC), which routinely analyzes threat information from external sources, monitors network activity, and responds to technological changepotential security incidents. In addition, our cybersecurity and may not be successful or may haveprivacy policies encompass incident response procedures and information security governance. As part of our ongoing assessment of our cybersecurity program, we monitor and make adjustments, as necessary, in support of compliance with current and emerging cybersecurity and privacy laws, regulations and guidance applicable to incur significant expendituresus in jurisdictions where we do business (including NERC CIP reliability standards and TSA security directives), as further described in Item 1A “Risk Factors.” Our internal audit team conducts regular internal security audits and vulnerability assessments of CenterPoint Energy’s systems and user data security practices.

In addition, CenterPoint Energy’s cybersecurity program is increasingly leveraging intelligence-sharing capabilities about emerging threats within the energy industry, across other industries, with specialized vendors, and through public-private partnerships with U.S. government intelligence agencies. By engaging with utility-specific organizations, CenterPoint Energy benefits from quality analysis and rapid sharing of security information across the energy sector. Such intelligence helps allow for better detection and prevention of emerging cyber threats before they materialize. Just as it tests its policies and plans internally, CenterPoint Energy also engages in external exercises such as the bi-annual GridEx Security Exercise to adapt to technological change.evaluate and address the preparedness of the industry as a whole.


Oversee Third-Party Risk

We operateconduct security risk assessments on proposed software, hardware, and third-party technology solutions used by CenterPoint Energy, including a diligence review of enterprise and security architecture, vendor security, and a privacy impact assessment when deemed appropriate. These assessments evaluate these technologies prior to deployment in businesses that require sophisticatedCenterPoint Energy’s network environment. Further, we maintain a vendor risk management program, a component of which assesses the maturity of certain third parties and their cybersecurity and data collection, processing systems, softwareprivacy programs to help protect information shared with approved third parties. We also leverage third-party cybersecurity ratings of companies to inform our risk rating when conducting these assessments. Additionally, CenterPoint Energy imposes contractual obligations on vendors and other technology. Somethird-party business partners related to privacy, confidentiality, and data security based on their access to our data and systems and the nature and sensitivity of the technologies supportingdata and systems. Such contractual provisions may specify the industriesmeasures and safeguards that the parties must implement to protect our data from unauthorized access use, disclosure, modification, or destruction.

Engage Third Parties on Risk Management

We also undergo periodic external security audits, vulnerability assessments, and penetration testing of CenterPoint Energy’s systems and user data security practice, conducted by third-party consultants. We also conduct tabletop exercises to
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test our incident response processes. Further, as discussed below, we serve are changing rapidlyengage third parties to provide guidance and increasingsupport to our cybersecurity management team.

Risks from Cybersecurity Threats

As described in complexity. New technologies will emergeItem 1A “Risk Factors,” our operations rely on the secure processing, storage, and transmission of confidential, sensitive, and other information within our computer systems and networks. Computer viruses, hackers, employee or grow that may be superior to, or may not be compatible with, somevendor incidents, and other external hazards could expose our information systems—and those of our existing technologies, and may require us to make significant expenditures so that we can continue tothird parties who process our data, provide cost-effective and reliable methods of energy delivery. Among such technological advances are distributed generation resources (e.g., private solar), energy storage devices and more energy-efficient buildings and products designed to reduce consumption. As these technologies become a more cost-competitive option


over time, whether through cost effectiveness or government incentives and subsidies, certain customers may choose to meet their own energy needs and subsequently decrease usage of our systems and services.

Our future success will depend, in part, on our ability to anticipate and adapt to these technological changes in a cost-effective manner and to offer, on a timely basis, reliable services that meet customer demands and evolving industry standards. If we fail to adapt successfully to any technological change or obsolescence, fail to obtain access to important technologiessystems, or incur significant expenditures in adaptingthat have access to technological change,our systems—to security breaches, cybersecurity incidents or if implemented technology does not operate as anticipated, our businesses, operating results, financial condition and cash flowsother disruptions, any of which could be materially and adversely affected.

Our or Enable’s potential business strategies and strategic initiatives, including merger and acquisition activities and the disposition of assets or businesses, may not be completed or perform as expected.

From time to time, we and Enable have made and may continue to make acquisitions or divestitures of businesses and assets, form joint ventures or undertake restructurings. However, suitable acquisition candidates or potential buyers may not continue to be available on terms and conditions we or Enable, as the case may be, find acceptable, or the expected benefits of completed acquisitions may not be realized fully or at all, or may not be realized in the anticipated timeframe. If we or Enable are unable to make acquisitions or if those acquisitions do not perform as anticipated, our and Enable’s future growth may be adversely affected.

Any completed or future acquisitions involve substantial risks, including the following:

acquired businesses or assets may not produce revenues, earnings or cash flow at anticipated levels;

acquired businesses or assets could have environmental, permitting or other problems for which contractual protections prove inadequate;

we or Enable may assume liabilities that were not disclosed to us, that exceed our estimates, or for which our rights to indemnification from the seller are limited;

we or Enable may be unable to integrate acquired businesses successfully and realize anticipated economic, operational and other benefits in a timely manner, which could result in substantial costs and delays or other operational, technical or financial problems; and

acquisitions, or the pursuit of acquisitions, could disrupt ongoing businesses, distract management, divert resources and make it difficult to maintain current business standards, controls and procedures.    

In February 2016, we announced that we were evaluating strategic alternatives for our investment in Enable, including a sale or spin-off qualifying under Section 355 of the U.S. Internal Revenue Code. We have determined that we will no longer pursue a spin option at this time. More recently, we announced that late-stage discussions with a third party regarding a transaction involving our investment in Enable had terminated because an agreement on mutually acceptable terms could not be reached. We may reduce our ownership in Enable over time through sales in the public equity markets, or otherwise, of the common units we hold, subject to market conditions. Although a transaction for all our interests in Enable is not viable at this time, we may pursue such a transaction if it is viable in the future. Our ability to execute any sale of common units is subject to a number of uncertainties, including the timing, pricing and terms of any such sale. Any sales of our common units could have an adverse impact on the price of Enable common units or on any trading market for Enable common units. Further, our sales of Enable common units may have an adverse impact on Enable’s ability to issue equity on satisfactory terms, or at all, which may limit its ability to expand operations or make future acquisitions. Any reduction in our interest in Enable would result in decreased distributions from Enable, which may reduce our operating income and adversely impact our ability to meet our payment obligations and pay dividends on our common stock. For a further discussion, please read “— Risk Factors Affecting Our Interests in Enable Midstream Partners, LP — Enable’s ability to grow is dependent on its ability to access external financing sources.”

There can be no assurances that we will engage in any specific action or that any sale transaction or any sale of common units in the public equity markets or otherwise will be completed, and we do not intend to disclose further developments unless and until our board of directors approves a specific action or as otherwise required by applicable law or NYSE regulations. Any sale transaction or sale of common units in the public equity markets or otherwise may involve significant costs and expenses, including, in connection with any public offering, a significant underwriting discount. We may not realize any or all of the anticipated strategic, financial, operational or other benefits from any completed sale or reduction in our investment in Enable.



We are involved in numerous legal proceedings, the outcome of which are uncertain, and resolutions adverse to us could negatively affect our financial results.

We are subject to numerous legal proceedings, the most significant of which are summarized in Note 15 of our consolidated financial statements. Litigation is subject to many uncertainties, and we cannot predict the outcome of all matters with assurance. Final resolution of these matters may require additional expenditures over an extended period of time that may be in excess of established insurance or reserves and may have a material adverse effect on our financial results.

We are exposed to risks related to reduction in energy consumption due to factors including unfavorable economic conditions in our service territories, energy efficiency initiatives and use of alternative technologies.

Our businesses are affected by reduction in energy consumption due to factors including economic climate in our service territories, energy efficiency initiatives and use of alternative technologies, which could impact our ability to grow our customer base and our rate of growth. Declines in demand for electricity as a result of economic downturns in our regulated electric service territory will reduce overall sales and lessen cash flows, especially as industrial customers reduce production and, therefore, consumption of electricity. Although Houston Electric is subject to regulated allowable rates of return and recovery of certain costs under periodic adjustment clauses, overall declines in electricity sold as a result of economic downturn or recession could reduce revenues and cash flows, thereby diminishing results of operations. Additionally, prolonged economic downturns that negatively impact ourbusiness, reputation, results of operations and cash flows could resultfinancial condition, and subject us to possible legal claims and liability. While we have experienced cybersecurity incidents in future material impairment chargesthe past, to write-down the carrying value of certain assets,date none have materially affected us, including goodwill, to their respective fair values.

For example, our electric business is largely concentrated in Houston, Texas, where a higher percentage of employment is tied to the energy sector relative to other regions of the country. During 2015 and 2016, the rate of growth in employment in Houston declined in connection with the significant decline in energy and commodity prices over that period. Relatively low commodity prices compared to pre-2015 levels continued in 2017, and we expect such relatively low prices to continue or slightly improve in 2018. In the event economic conditions further decline, the rate of growth in Houston and the other areas in which we operate may also deteriorate. Increases in customer defaults or delays in payment due to liquidity constraints could negatively impact our cash flows and financial condition.

Growth in customer accounts and growth of customer usage each directly influence demand for electricity and the need for additional delivery facilities. Customer growth and customer usage are affected by a number of factors outside our control, such as mandated energy efficiency measures, demand-side management goals, distributed generation resources and economic and demographic conditions, such as population changes, job and income growth, housing starts, new business formation and the overall level of economic activity.

Certain regulatory and legislative bodies have introduced or are considering requirements and/or incentives to reduce energy consumption by certain dates. Additionally, technological advances driven by federal laws mandating new levels of energy efficiency in end-use electric devices or other improvements in or applications of technology could lead to declines in per capita energy consumption.

Some or all of these factors, could result in a lack of growth or decline in customer demand for electricity or number of customers, and may result in our failure to fully realize anticipated benefits from significant capital investments and expenditures which could have a material adverse effect on their financial position, results of operations and cash flows.

Furthermore, we currently have energy efficiency riders in place to recover the cost of energy efficiency programs. Should we be required to invest in conservation measures that result in reduced sales from effective conservation, regulatory lag in adjusting rates for the impact of these measures could have a negative financial impact.

If we fail to maintain an effective system of internal controls, our ability to accurately report our financial condition,strategy, results of operations or cash flowsfinancial condition.

Governance

As part of our overall risk management approach, we prioritize the identification and management of cybersecurity risks at several levels, including Board oversight, executive commitment, management support, and employee training.

Board of Directors Oversight

As of December 2023, our Audit Committee, comprised of independent directors from our Board, oversees the Board’s responsibilities relating to CenterPoint Energy’s cybersecurity and data privacy programs, including cybersecurity risk management. Prior to December 2023, our Governance, Environmental and Sustainability Committee, comprised of independent directors from our Board, oversaw cybersecurity responsibilities. As part of their risk oversight responsibilities, the applicable committee received quarterly reports from our Executive Vice President and General Counsel, or prevent fraud may be adversely affected. As a result, investors could lose confidencerepresentatives from our cybersecurity or data privacy groups, and periodic reports from our third party consultants. Based on these reports, the applicable committee reported to the Board regarding certain cybersecurity or data privacy related items, including, among other items, CenterPoint Energy’s progress in our financial reporting, which could impact our businessesmaturing its cybersecurity program, results of audits, penetration and vulnerability testing of CenterPoint Energy’s cybersecurity program, the cybersecurity landscape and emerging threats, status of ongoing initiatives and strategies, incident reports and learnings from any cybersecurity events, compliance with regulatory requirements and industry standards, data privacy matters, and the trading pricecybersecurity budget.

Risk Management Personnel

Since January 2023, our cybersecurity program has been overseen by our Executive Vice President and General Counsel. Our Executive Vice President and General Counsel has significant risk management, governance and litigation experience. We believe these skills are needed in leadership of our securities. 

Effective internal controlscybersecurity program to help ensure that risk management, legal, disclosure and governance perspectives are necessary for usconsidered in the design of our cybersecurity program and in evaluating and responding to potential cyber incidents.CenterPoint Energy currently engages a third-party consultant, who reports directly to the Executive Vice President and General Counsel, to provide reliable financial reports, effectively prevent fraud and operate successfullyChief Information Security Officer (CISO) advisory services. This consultant has 15 years of experience serving in cybersecurity leadership positions, including as a publicCISO at a large U.S.-based power, utility, and gas company and also at a large multi-national energy products and services company. IfWe also have management-level committees and an experienced CSOC team that support our effortsprocesses to maintain an effective system of internal controls are not successful, we are unable to maintain adequate controls overassess and manage cybersecurity risk as follows:

•The Data Privacy Office, led by our financial reporting and processes in the future or we are unable to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002, our operating results could be harmed or we may fail to meet our reporting obligations. Ineffective internal controls also could cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our securities.



Our businesses may be adversely affected by the intentional misconduct of our employees.

We are committed to living our core values of safety, integrity, accountability, initiative and respect and complying with all applicable laws and regulations. Despite that commitment and our efforts to prevent misconduct, it is possible for employees to engage in intentional misconduct, fail to uphold our core values, and violate laws and regulations for individual gain through contract or procurement fraud, misappropriation, bribery or corruption, fraudulent related-party transactions and serious breaches of ourSenior Vice President, Deputy General Counsel, Chief Ethics and Compliance CodeOfficer, and StandardsData Privacy Officer, addresses the collection, storage, usage, disclosure and destruction of Conduct/Business Ethics policy, among other policies. If such intentional misconductdata for specific business purposes and addresses existing and emerging laws, regulations, trends, expectations and best practices with regards to maintaining a mature data privacy program.

•The Risk Oversight Committee, which is supported by employees should occur, it could resultour Enterprise Risk Management function and chaired by our Executive Vice President and General Counsel, is comprised of senior executives from across CenterPoint Energy, monitors and oversees risks facing CenterPoint Energy, as well as provides risk assessments and control oversight for certain business activities, including overseeing CenterPoint Energy’s cybersecurity risks.

•The crisis management team, which includes senior executives across CenterPoint Energy, is alerted as appropriate to cybersecurity incidents, natural disasters, and business outages. This team has established and continually assesses CenterPoint Energy’s communications plan in substantial liability, higher costs, increased regulatory scrutinythe event of a crisis. Additionally, as appropriate, the Audit Committee
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or the Board are made aware of significant cybersecurity incidents in accordance with our cybersecurity incident response playbook.

•The Cybersecurity Awareness Governance Committee, which includes leaders from across CenterPoint Energy’s corporate functions and negative public perceptions, anybusiness units, each with expertise in, or with specific responsibility for, managing or protecting CenterPoint Energy’s assets, information and personnel. This committee provides strategic direction and oversight for CenterPoint Energy’s cybersecurity awareness and training initiatives.

•The Artificial Intelligence (AI) Steering Committee was established by CenterPoint Energy to provide strategic direction, oversight, and guidance in the planning, development, deployment, and management of which could have a material adverse effectAI initiatives within the organization. The committee's primary objective is to ensure that AI technologies are aligned with business goals, ethical considerations, appropriate security protections, and industry best practices while driving innovation and enhancing competitiveness.

These committees provide periodic summary reports on their activities and initiatives to appropriate senior executives, and the Executive Vice President and General Counsel and/or various members of the cyber and data privacy teams communicates updates to the Audit Committee or the Board.

At the employee level, we maintain an experienced information technology team that is tasked with implementing our privacy and cybersecurity programs and supporting the cybersecurity consultant in carrying out reporting, security and mitigation functions. We also hold employee trainings on privacy, cybersecurity, AI, records and information management, conduct phishing tests, and generally seek to promote awareness of cybersecurity risk through communication and education of our employee population. The Governance, Environmental and Sustainability Committee was, and now the Audit Committee will be, provided with periodic reports on our resultsemployee cybersecurity awareness efforts.

Item 2.Properties

The following discussion is based on the Registrants’ businesses as of operations, financial condition and cash flows.December 31, 2023.

Item 1B.Unresolved Staff Comments

None.

Item 2.Properties


Character of Ownership


We lease or own our principal properties in fee, including our corporate office space and various real property. Most of our electric lines and natural gas mains are located, pursuant to easements and other rights, on public roads or on land owned by others.


Electric Transmission & Distribution(CenterPoint Energy and Houston Electric)


Properties

All of Houston Electric’s properties are located in Texas. Its properties consist primarily of high-voltage electric transmission lines and poles, distribution lines, substations, service centers, service wires, telecommunications networks and meters. Most of Houston Electric’s transmission and distribution lines have been constructed over lands of others pursuant to easements or along public highways and streets under franchise agreements and as permitted by law.
All real and tangible properties of Houston Electric, subject to certain exclusions, are currently subject to the lien of the M&DOT and the lien of the General Mortgage, which is junior to the lien of the M&DOT.

No first mortgage bonds are outstanding under the M&DOT and Houston Electric is contractually obligated to not issue any additional first mortgage bonds under the M&DOT and is undertaking actions to release the lien of the M&DOT and terminate the M&DOT. For information regardingrelated to debt outstanding under the General Mortgage, see Note 13 to the consolidated financial statements.

Indiana Electric’s properties are primarily located in Indiana. They consist of transmission lines in Indiana and Kentucky, distribution lines, substations, service centers, coal-fired generating facilities, gas-fired turbine peaking units, a landfill gas electric generation project and solar generation facilities.

All real and tangible properties of ourIndiana Electric, subject to certain exclusions, are currently subject to the lien of the Amended and Restated Mortgage Indenture dated as of January 1, 2023, between SIGECO (Indiana Electric) and Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company), as Trustee.
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Electric Lines - Transmission and Distribution. As of December 31, 2023, Houston Electric and Indiana Electric owned and operated the following electric transmission and distribution lines:
Houston ElectricIndiana Electric
DescriptionOverhead LinesUnderground LinesIndianaKentucky (1)
Transmission lines:(in Circuit Miles)
69 kV132 2 567 — 
138 kV2,333 24 420 9 
345 kV1,445 — 49 15 
Total3,910 26 1,036 24 
(in Circuit Miles)
Distribution lines29,270 27,267 7,266 — 

(1)These assets interconnect with Louisville Gas and Electric Company’s transmission system at Cloverport, Kentucky and with Big Rivers Electric Cooperative at Sebree, Kentucky.

Generating Capacity. In 2023, SIGECO completed the planned retirement of its A.B. Brown Units 1 & Distribution business segment, please read “Business2. As of December 31, 2023, Indiana Electric had 727 MW of installed generating capacity, as set forth in the following table.
Generation SourceUnit No.LocationDate in ServiceCapacity
(MW)
Coal
F.B. Culley2Warrick County196690 
F.B. Culley3Warrick County1973270 
Warrick (1)
4Warrick County1970150 
Total Coal Capacity510 
Gas
Brown (2)
3Posey County199180 
Brown4Posey County200280 
Renewable Landfill GasPike County20093 
Total Gas Capacity163 
Solar
Oak HillEvansville, Indiana20182 
VolkmanEvansville, Indiana20182 
TroySpencer County202150 
Total Solar Capacity54 
Total Generating Capacity (3)
727 

(1)SIGECO and AGC own a 300 MW unit at the Warrick Power Plant as tenants in common. SIGECO exited joint operations of Warrick 4 on January 1, 2024.
(2)Brown Unit 3 is also equipped to burn oil.
(3)Excludes 1.5% participation in OVEC. See Item 1. Business for more details.

Natural Gas Combustion Turbines. In 2022, Indiana Electric received approval from the IURC for a CPCN seeking approval to construct two natural gas combustion turbines to replace portions of its existing coal-fired generation fleet. The turbines are targeted to be operational by year end 2025. For further information, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Our BusinessLiquidity and Capital Resources — Electric Transmission & Distribution — Properties”Regulatory Matters” in Item 17 of Part II of this report, which informationdiscussion is incorporated herein by reference.


Natural Gas Distribution

Solar. Indiana Electric entered into an amended and restated BTA to build a 191 MW solar array in Posey County, Indiana. Additionally, 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. For further information regarding the propertiesabout Indiana Electric’s BTA’s, see “Management’s Discussion and Analysis of our Natural Gas Distribution business segment, please read “BusinessFinancial Condition and Results of Operations — Our BusinessLiquidity and Capital Resources — Natural Gas Distribution — Assets”Regulatory Matters” in Item 17 of Part II of this report, which informationdiscussion is incorporated herein by reference.

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Mobile Generation. As allowed by a law enacted by the Texas legislature after the February 2021 Winter Storm Event and amended in 2023, Houston Electric is leasing TEEEF that can aid in restoring power to customers during certain significant power outages that are impacting its distribution system. As of December 31, 2023, Houston Electric leased 505 MW of TEEEF. For more information, see Note 20 to the consolidated financial statements.

Substations.  A substation is a facility that transforms electricity from a higher voltage to a lower voltage or vice versa. Generally, this facility is the interface between the transmission system and the distribution grid.

As of December 31, 2023
 Number of SubstationsTransformer Capacity (in Mva)
Houston Electric240 72,806 
Indiana Electric108 6,913 
Total CenterPoint Energy348 79,719 

Service Centers.  Service centers consist of office buildings, warehouses and repair facilities that are used in the business of transmitting and distributing electricity.

As of December 31, 2023
 Number of Service CentersAcres of Land
Houston Electric13 375 
Indiana Electric6 70 
Total CenterPoint Energy19 445 

Natural Gas (CenterPoint Energy Servicesand CERC)


For information regardingCenterPoint Energy’s and CERC’s Natural Gas use various third-party storage services or owned natural gas storage facilities to meet peak-day requirements and to manage the propertiesdaily changes in demand due to changes in weather. CenterPoint Energy’s and CERC’s Natural Gas may also supplement contracted supplies and storage from time to time with stored LNG and propane-air plant production.

As of ourDecember 31, 2023, CenterPoint Energy’s and CERC’s Natural Gas owned and operated the following natural gas facilities:
No. of AssetsStorage Capacity (Bcf)Working Capacity (Bcf) Maximum Daily Withdrawal Rate (MMcf)
CenterPoint Energy
Underground Natural Gas Storage Facility843 14 305 
CERC
Underground Natural Gas Storage Facility532 9 205 
On-site Storage Capacity
No. of AssetsDaily Production Rate (Dth)Millions of GallonsDth
CenterPoint Energy and CERC
Propane Air-Gas Manufacturing Plant16247,000 14.11,228,000 
LNG Plant Facility172,000 12.01,010,000 

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The table below reflects CenterPoint Energy’s and CERC’s Natural Gas contracted upstream storage services as of December 31, 2023:
Storage Capacity (Bcf) Maximum Peak Daily Delivery (MMcf)
Upstream Storage Service84 2,241 
The table below reflects the approximate total linear miles of CenterPoint Energy’s and CERC’s Natural Gas distribution and transmission mains owned as of December 31, 2023:
CenterPoint EnergyCERC
All Locations84,000 81,000 
Indiana and Ohio22,000 19,000 

CenterPoint Energy’s and CERC’s Natural Gas owned mains varying in size from one-half inch to 24 inches in diameter. CenterPoint Energy’s and CERC’s Natural Gas Indiana and Ohio mains are located in Indiana and Ohio except for, in the case of CenterPoint Energy, Services business segment, please read “Business — Our Business —pipeline facilities extending from points in northern Kentucky to points in southern Indiana so that gas may be transported to Indiana and sold or transported to customers in Indiana. Generally, in each of the cities, towns and rural areas served by CenterPoint Energy’s and CERC’s Natural Gas, they own the underground gas mains and service lines, metering and regulating equipment located on customers’ premises and the district regulating equipment necessary for pressure maintenance. With a few exceptions, the measuring stations at which CenterPoint Energy’s and CERC’s Natural Gas receives gas are owned, operated and maintained by others, and their distribution facilities begin at the outlet of the measuring equipment. These facilities, including odorizing equipment, are usually located on land owned by suppliers.

As of December 31, 2023, CenterPoint Energy Services — Assets”and CERC, through CEIP, owned and operated over 217 miles of intrastate pipeline in Louisiana and Texas.

Item 1 of this report, which information is incorporated herein by reference.3.Legal Proceedings
Midstream Investments

For information regarding the properties of our Midstream Investments business segment, please read “Business — Our Business — Midstream Investments” in Item 1 of this report, which information is incorporated herein by reference.

Other Operations

For information regarding the properties of our Other Operations business segment, please read “Business — Our Business — Other Operations” in Item 1 of this report, which information is incorporated herein by reference.

Item 3.Legal Proceedings


For a discussion of material legal and regulatory proceedings, including environmental legal proceedings that involve a governmental authority as a party and that the Registrants reasonably believe would result in $1,000,000 or more of monetary sanctions, exclusive of interest and costs, under federal, state and local laws that have been enacted or adopted regulating the discharge of materials into the environment or primarily for the purpose of protecting the environment, affecting us,the Registrants, please read “Business — Regulation” and “Business — Environmental Matters” in Item 1 of this report, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Regulatory Matters” in Item 7 of Part II of this report and Note 15(d) to ourthe consolidated financial statements, which information is incorporated herein by reference.


Item 4.Mine Safety Disclosures

Item 4.Mine Safety Disclosures

Not applicable.




PART II


Item 5.Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

This combined Form 10-K is filed separately by three registrants: CenterPoint Energy, Houston Electric and CERC.

Item 5.Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

CenterPoint Energy

As of February 9, 2018, our12, 2024, CenterPoint Energy’s common stock was held by approximately 30,49322,703 shareholders of record. OurCenterPoint Energy’s common stock is listed on the NYSE and NYSE Chicago Stock Exchange and is traded under the symbol “CNP.”

The following table sets forth the high and low closing prices of the common stock of CenterPoint Energy on the NYSE composite tape during the periods indicated, as reported by Bloomberg, and the cash dividends declared in these periods.
 
 Market Price
 
Dividend
Declared
 High Low Per Share
2017     
First Quarter    $0.2675
January 3  $24.59
  
March 15$28.09
    
Second Quarter    $0.2675
May 17  $27.17
  
June 1$28.93
    
Third Quarter    $0.2675
July 11  $27.16
  
September 11$30.45
    
Fourth Quarter (1)
    $0.5450
November 30$30.01
    
December 21  $27.77
  
      
2016     
First Quarter    $0.2575
January 20  $16.90
  
March 29$21.25
    
Second Quarter    $0.2575
April 5  $20.51
  
June 29$24.00
    
Third Quarter    $0.2575
July 22$24.69
    
August 16  $22.13
 ��
Fourth Quarter    $0.2575
October 11  $21.84
  
December 22$24.84
    

(1)On October 25, 2017, our Board of Directors declared a regular quarterly cash dividend of $0.2675 per share of common stock payable on December 8, 2017, to shareholders of record as of the close of business on November 16, 2017. On December 13, 2017, our Board of Directors declared a regular quarterly cash dividend of $0.2775 per share, payable on March 8, 2018 to shareholders of record at the close of business on February 15, 2018.

The closing market price of our common stock on December 31, 2017 was $28.36 per share.


The amount of future cash dividends will be subject to determination based upon ourCenterPoint Energy’s financial condition and results of operations, and financial condition, our future business prospects, any applicable contractual restrictions and other factors that ourCenterPoint Energy’s Board of Directors considers relevant and will be declared at the discretion of theCenterPoint Energy’s Board of Directors. For further information on CenterPoint Energy’s dividends, see Note 12 to the consolidated financial statements.

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Repurchases of Equity Securities


During the quarter ended December 31, 2017,2023, none of ourCenterPoint Energy’s equity securities registered pursuant to Section 12 of the Securities Exchange Act of 1934, as amended, were purchased by or on behalf of usCenterPoint Energy or any of our “affiliated purchasers,” as defined in Rule 10b-18(a)(3) under the Securities Exchange Act of 1934.1934, as amended.


Houston Electric

As of February 12, 2024, all of Houston Electric’s 1,000 outstanding common shares were held by Utility Holding, LLC, a wholly-owned subsidiary of CenterPoint Energy.

CERC

As of February 12, 2024, all of CERC Corp.’s 1,000 outstanding shares of common stock were held by Utility Holding, LLC, a wholly-owned subsidiary of CenterPoint Energy.

Item 6.        Selected[Reserved]

Item 7.Management’s Discussion and Analysis of Financial DataCondition and Results of Operations


No Registrant makes any representations as to the information related solely to CenterPoint Energy or the subsidiaries of CenterPoint Energy other than itself.

The following table presents selected financial data with respect to our consolidated financial condition and consolidated results of operations and should be read in conjunction with our consolidated financial statements and the related notes in Item 8 of this report.
 Year Ended December 31,
 2017 2016 2015 2014 2013
 (in millions, except per share amounts)
Revenues$9,614
 $7,528
 $7,386
 $9,226
 $8,106
Equity in earnings (losses) of unconsolidated affiliates265
 208
 (1,663)(2)308
 188
Net income (loss)1,792
(1)432
 (692) 611

311
Basic earnings (loss) per common share4.16
 1.00
 (1.61) 1.42

0.73
Diluted earnings (loss) per common share4.13
 1.00
 (1.61) 1.42

$0.72
          
Cash dividends paid per common share$1.07
 $1.03
 $0.99
 $0.95
 $0.83
Dividend payout ratio26% 103% n/a

67%
114%
Return on average common equity44% 12% (17)% 14% 7%
Ratio of earnings to fixed charges3.70
 2.74
 2.67
 2.79
 2.42
At year-end:         
Book value per common share$10.88
 $8.04
 $8.05
 $10.58
 $10.09
Market price per common share28.36
 24.64
 18.36
 23.43
 23.18
Market price as a percent of book value261% 306% 228 % 221% 230%
Percentage of common units owned representing limited partner interests in Enable54.1% 54.1% 55.4 % 55.4% 58.3%
Total assets (4)
$22,736
 $21,829
 $21,290
 $23,150
 $21,816
Short-term borrowings39
 35
 40
 53
 43
Securitization Bonds, including current maturities (3)
1,868
 2,278
 2,667
 3,037
 3,388
Other long-term debt, including current maturities (3)
6,933
 6,279
 6,063
 5,717
 4,873
Capitalization:         
Common stock equity35% 29% 28 % 34% 34%
Long-term debt, including current maturities65% 71% 72 % 66% 66%
Capitalization, excluding Securitization Bonds:         
Common stock equity40% 36% 36 % 44% 47%
Long-term debt, excluding Securitization Bonds, and including current maturities60% 64% 64 % 56% 53%
Capital expenditures$1,494
 $1,406
 $1,575
 $1,402
 $1,272

(1)Net income for the year ended December 31, 2017 includes a reduction in income taxes of $1,113 million due to tax reform. See Note 14 to our consolidated financial statements for further discussion of the impacts of tax reform implementation.

(2)This amount includes $1,846 million of non-cash impairment charges related to Enable.

(3)Amounts for 2013 to 2015 have been restated to reflect adoption of ASU 2015-03.




Item 7.Management’s Discussion and Analysis of Financial Condition and Results of Operations

The followingcombined discussion and analysis should be read in combination with ourthe consolidated financial statements included in Item 8 herein. When discussing CenterPoint Energy’s consolidated financial information, it includes the results of Houston Electric and CERC, which, along with CenterPoint Energy, are collectively referred to as the Registrants. Where appropriate, information relating to a specific registrant has been segregated and labeled as such. Unless the context indicates otherwise, specific references to Houston Electric and CERC also pertain to CenterPoint Energy. In this combined Form 10-K, 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 stated otherwise.


OVERVIEW


Background


We areCenterPoint Energy, Inc. is a public utility holding company. OurCenterPoint Energy’s operating subsidiaries own and operate electric transmission, distribution and distributiongeneration and natural gas distribution facilities, supply natural gasfacilities. For a detailed description of CenterPoint Energy’s operating subsidiaries, please read Note 1 to commercial and industrial customers and electric and natural gas utilities and own interests in Enable as described below. Our indirect, wholly-owned subsidiaries include:the consolidated financial statements.


Houston Electric which engagesis an indirect, wholly-owned subsidiary of CenterPoint Energy that provides electric transmission service to transmission service customers in the electric transmissionERCOT region and distribution business inservice to REPs serving the Texas Gulf Coastgulf coast area that includes the city of Houston;Houston.


CERC Corp., which is an indirect, wholly-owned subsidiary of CenterPoint Energy that (i) directly owns and operates natural gas distribution systems in six states;Louisiana, Minnesota, Mississippi and

CES, which obtains Texas, (ii) indirectly, through Indiana Gas and offers competitive variableVEDO, owns and fixed-price physicaloperates natural gas suppliesdistribution systems in Indiana and services primarily to commercialOhio, respectively, and industrial customers(iii) owns and electricoperates permanent pipeline connections through interconnects with various interstate and natural gas utilities in 33 states.intrastate pipeline companies through CEIP.


As of December 31, 2017, we also owned an aggregate of 14,520,000 Series A Preferred Units in Enable, which owns, operates and develops natural gas and crude oil infrastructure assets, and CERC Corp. owned approximately 54.1% of the common units representing limited partner interests in Enable.

BusinessReportable Segments


In this Management’s Discussion and Analysis, we discuss our results from continuing operations on a consolidated basis and individually for each of our business segments.reportable segments, which are listed below. We also discuss our liquidity, capital resources and critical accounting policies. We are first and foremost an energy delivery company and it is our intention to remain focused on these segments of the energy business.regulated segments. The results of our business operations are significantly impacted by weather, customer growth, economic conditions, cost management, competition, rate proceedings before regulatory agencies and other actions of the various regulatory agencies to whose jurisdiction we are subject. Oursubject, among other factors.

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As of December 31, 2023, CenterPoint Energy’s reportable segments were Electric, Natural Gas, and Corporate and Other.

•The Electric reportable segment includes electric transmission and distribution services that are subject to rate regulation in Houston Electric’s and are reported inIndiana Electric’s service territories, as well as the Electric Transmission & Distribution business segment, as are impacts of generation-related stranded costs and other true-up balances recoverable by the regulated electric utility.utility and energy delivery services to electric customers and electric generation assets to serve electric customers and optimize those assets in the wholesale power market in Indiana Electric’s service territory. For further information about ourthe Electric Transmission & Distribution businessreportable segment, see “Business — Our Business — Electric Transmission & Distribution”Electric” in Item 1 of Part I of this report. Our

•The Natural Gas reportable segment includes (i) intrastate natural gas sales to, and natural gas transportation and distribution for residential, commercial, industrial and institutional customers in Indiana, Louisiana, Minnesota, Mississippi, Ohio and Texas; (ii) permanent pipeline connections through interconnects with various interstate and intrastate pipeline companies through CEIP; and (iii) home appliance maintenance and repair services are also subject to rate regulationcustomers in Minnesota and are reportedhome repair protection plans to natural gas customers in the Natural Gas Distribution business segment.Indiana, Mississippi, Ohio and Texas through a third party. For further information about ourthe Natural Gas Distribution businessreportable segment, see “Business — Our Business — Natural Gas Distribution”Gas” in Item 1 of Part I of this report. Our Energy Services business

•The Corporate and Other reportable segment includes non-rate regulated natural gas sales to,energy performance contracting and transportationsustainable infrastructure services by Energy Systems Group through June 30, 2023, the date of the sale of Energy Systems Group, and storage services, for commercialcorporate support operations that support CenterPoint Energy’s business operations. CenterPoint Energy’s Corporate and industrial customers. For further information about our Energy Services business segment, see “Business — Our Business — Energy Services” in Item 1 of Part I of this report.The results of our Midstream Investments business segment are dependent upon the results of Enable, which are driven primarily by the volume of natural gas, NGLs and crude oil that Enable gathers, processes and transports across its systems and other factors as discussed below under “— Factors Influencing Our Midstream Investments Segment.” Our Other Operations business segmentalso includes office buildings and other real estate used in our business operations and other corporate operations which support all of ourfor business operations.


Houston Electric and CERC each consist of a single reportable segment.

Subsequent Events. 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 local distribution company businesses. The transaction is expected to close in the first quarter of 2025. For further information, see Note 21 to the consolidated financial statements.

EXECUTIVE SUMMARY

Factors Influencing Our Businesses and Industry Trends

We expect our and Enable’s businesses to continue to be affected by the key factors and trends discussed below. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove to be incorrect, our actual results may vary materially from our expected results.


Factors Influencing Our Businesses and Industry Trends

We are an energy delivery company.company with electric transmission and distribution, power generation, and natural gas distribution operations that serve more than seven million metered customers across six jurisdictions. The majority of our revenues are generated from the sale of natural gas and the transmission and delivery of electricity and the sale of natural gas by our subsidiaries.

We do not own or operate electric generating facilities or make retail salescontinue to end-use electric customers. To assessexecute on our financial performance,strategic goals for our management primarily monitors operating income and cash flowsbusinesses which were set in 2021. These include our ten-year capital plan from our business segments. Within these broader financial measures, we monitor margins, operation2021 through 2030, a focus on targeting controllable operations and maintenance expense,


interest expense, capital spending and working capital requirements. In addition to these financial measures, we also monitor a number of variables that management considers important tosavings for the operation of our business segments, including the number of customers, throughput, use per customer, commodity prices and heating and cooling degree days. We also monitor system reliability, safety factors and customer satisfaction to gauge our performance.

To the extent adverse economic conditions affect our suppliers and customers, results from our energy delivery businesses may suffer. For example, our electric business is largely concentrated in Houston, Texas, where a higher percentage of employment is tied to the energy sector relative to other regions of the country. Although Houston, Texas has a diverse economy, employment in the energy industry remains important. During 2015 and 2016, the rate of growth in employment in Houston declined in connection with the significant decline in energy and commodity prices over that period. Relatively low commodity prices compared to pre-2015 levels continued in 2017, and we expect such relatively low prices to continue or slightly improve in 2018.

Also, adverse economic conditions, coupled with concerns for protecting the environment and increased availability of alternate energy sources, may cause consumers to use less energy or avoid expansions of their facilities, resulting in less demand for our services. To the extent population growth is affected by lower energy prices and there is financial pressure on somebenefit of our customers, who operate within the energy industry, there mayprudent capital funding including divestitures of non-core assets, and net zero and carbon emission reduction goals. Our focus continues to be an impact on the growth rate of our customer base and overall demand. Due to a slowdown in multi-family residential construction, meter growth in 2017 has declined. We saw year-over-year residential meter growth decline from 2.3% in 2016 to 1.6% in 2017. As the recent stability in the energy sector gains momentum in 2018, we anticipate this growth will continue at roughly 2%, in line with long-term trends.

Performance of our Electric Transmission & Distribution and Natural Gas Distribution business segments is significantly influenced by the number of customers and energy usage per customer. Weather conditions can have a significant impact on energy usage, and we compare our results on a weather-adjusted basis. 

Overall, in 2017 the Houston area experienced a number of record-breaking high and low temperatures, primarily in January-April and in October-November, resulting in a year that was warmer by a tenth of a degree than the previous warmest year, 2012. In terms of heating degree days, Texas recorded its warmest year and for most other jurisdictions the second warmest year since 1970. In 2017, our Houston service area experienced above normal warmth with record rainfall during Hurricane Harvey. In 2016, our Houston service area experienced above normal warmth with episodes of flooding. In 2015, our Houston service area experienced some of the mildest temperatures on record during November and December. Every state in which we distribute natural gas had a warmer than normal winter in 2017, 2016 and 2015.

Historically, both the TDU and NGD have utilized weather hedges to help reduce the impact of mild weather on their financial results. The TDU entered into a weather hedge for the 2015-2016, 2016-2017 and 2017-2018 winter heating seasons. However, although NGD did not enter into a weather hedge for the winter of 2015-2016 or 2016-2017, it has entered into a hedge for the 2017-2018 winter season in Texas where no weather normalization mechanisms exist. In our non-Texas jurisdictions, weather normalization mechanisms or decoupling in the Minnesota division help to mitigate the impact of abnormal weather on our financial results. Long-term national trends indicate customers have reduced their energy consumption, which could adversely affect our results. However, due to more affordable energy prices and continued economic improvement in the areas we serve, the trend toward lower usage has slowed. 

In Minnesota and Arkansas, there are rate adjustment mechanisms to counter the impact of declining usage from energy efficiency improvements. In addition, in many of our service areas, particularly in the Houston area and Minnesota, we have benefited from growth in the number of customers, which could mitigate the effects of reduced consumption.  We anticipate that this trend will continue as the regions’ economies continue to grow. The profitability of ourregulated utility businesses is influenced significantly by the regulatory treatment we receive from the various state and local regulators who setincluding our electric and gas distribution rates.utility operations, which comprise over 95% of our earnings for the year ended December 31, 2023. See Note 11 to the consolidated financial statements for further details.


Our Energy Services business segment contracts with customers for transportation, storage and sales of natural gas on an unregulated basis.  Its operations serve customers throughout the United States.  The segment benefits from favorable price differentials, either on a geographic or seasonal basis. WhilePursuant to this business utilizes financial derivatives to mitigatestrategy and in light of the effects of price movements, it does not enter into risk management contracts for speculative purposes and monitors VaR daily to avoid significant financial exposures to realized income.  At the end of 2017, a weather-driven spike in natural gas prices caused the accrual of unusually high unrealized mark-to-market income, expected to be substantially reversed in the first quarter of 2018 as natural gas prices normalize.

In January 2017, CES acquired AEM, which included approximately 1,000 customers and 362 Bcf of natural gas sales. The customer base included more industrial customers, which was complementary to our existing commercial-heavy customer base. This acquisition helped drive the overall operating income increase for Energy Services in 2017 as compared to 2016. For more information regarding this acquisition, see Note 4 to our consolidated financial statements.



The nature of our businesses, requires significant amounts of capital investment are reflected in our current capital plan, which has increased to nearly $44 billion through 2030, a nearly 10% increase from the original 10-year plan. These investments include a focus on additional system resiliency, reliability, and grid modernization. These investments are not only intended to meet our customers’ current needs, but are also in anticipation for further organic growth and load growth from increased electrification in our service territories. To fund these capital investments, we rely on internally generated cash, borrowings under our credit facilities, proceeds from commercial paper, cash proceeds from strategic transactions (such as the sale of our Arkansas and Oklahoma LDC businesses in 2022 and our Energy Systems Group divestiture in 2023), and issuances of debtequity and equitydebt in the capital markets to satisfy these capital needs.

We strive to maintain investment grade ratings for our securities to access the capital markets on terms we consider reasonable. A reduction in our ratings generally would increase our borrowing costs for new issuances of debt, as well as
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borrowing costs under our existing revolving credit facilities, and may prevent us from accessing the commercial paper markets. Disruptions in the financial markets along with high or rising interest rates can also affect the availability of new capital on terms we consider attractive. In those circumstances, companies like uswe may not be able to obtain certain types of external financing or may be required to accept terms less favorable than they would otherwise accept. For that reason, we seek to maintain adequate liquidity for our businesses through existing credit facilities and prudent refinancing of existing debt.


The regulation of electric transmission, distribution and generation facilities as well as natural gas pipelines and related facilities by federal and state regulatory agencies affects our business.CenterPoint Energy’s, Houston Electric’s and CERC’s businesses. In accordance with natural gas pipeline safetyapplicable regulations, CenterPoint Energy, Houston Electric and integrity regulations, weCERC are making, and will continue to make, significant capital investments in ourtheir service territories which are necessaryunder our capital plan to help operate and maintain a safe,safer, more reliable and growing electric and natural gas system. Our compliance expenses may also increase as a resultsystems. The current economic environment (e.g., sustained higher interest rates and higher relative levels of preventative measures required under these regulations. Consequently, new ratesinflation in the areas we serveUnited States) discussed further below could result in heightened regulatory scrutiny as these regulatory agencies seek to reduce the financial impact of utility bills on customers.

While greater than 80% of CenterPoint Energy’s projected consolidated investments are necessaryexpected to be recovered through interim capital recovery trackers or rate cases based on a forward test year, the balance is expected to be recovered through base rate cases.CERC’s Texas and Minnesota gas jurisdictions along with Indiana Electric have filed rates cases during 2023, and Houston Electric intends to file a rate case in early 2024 and CERC’s Ohio jurisdiction intends to file a rate case in the second half of 2024. The outcome of these base rate proceedings will determine, among other things, the ability to recover certain capital investments within those jurisdictions. The outcome of these increasing costs.

We expect to contribute a minimum of approximately $67 million to our pension plans in 2018. Consistent with the regulatory treatment of such costs, we defer the amount of pension expense that differs from the level of pension expense included in our base rates for our Electric Transmission & Distribution business segmentrate proceedings is uncertain and Natural Gas Distribution business segment in Texas.

Factors Influencing Our Midstream Investments Segment
The results of our Midstream Investments segment are dependent upon the results of Enable, which are driven primarily by the volume of natural gas, NGLs and crude oil that Enable gathers, processes and transports across its systems. These volumes depend significantly on the level of production from natural gas wells connected to Enable’s systems across a number of U.S. mid-continent markets. Aggregate production volumes are affected by the overall amount of oil and gas drilling and completion activities. Production must be maintained or increased by new drilling or other activity, because the production rate of oil and gas wells declines over time.

Enable expects its business to continue tomay be impacted by the trends affectingcurrent economic environment.

To assess our financial performance, our management primarily monitors the midstream industry, discussed below. Enable’s outlook is basedrecovery of costs and return on its management’s assumptions regardinginvestments by the impactevaluation of net income and capital expenditures, among other things, from our regulated service territories within our reportable segments. Within these trends that it has developed by interpreting the information currently available to them. If Enable management’s assumptions or interpretation of available information prove to be incorrect, Enable’s futurebroader financial condition and results of operations may differ materially from its expectations.

Enable’s business is impacted by commodity prices, which have declined and otherwise experienced significant volatility in recent years. Commodity prices impact the drilling and production ofmeasures, we monitor margins, natural gas and crude oil in the areas served by Enable’s systems,fuel costs, interest expense, capital spend, working capital requirements, and the volumes on Enable’s systems are negatively impacted if producers decrease drillingoperation and production in those areas served. Both Enable’s gathering and processing segment and its transportation and storage segment can be impacted by drilling and production. Enable’s gathering and processing segment primarily serves producers, and many producers utilize the services provided by its transportation and storage segment. A decrease in volumes will decrease cash flows from Enable’s systems.maintenance expense. In addition Enable’s processing arrangements expose it to these financial measures, we also monitor a number of variables that management considers important to gauge the performance of our reportable segments, including the number of customers, throughput, use per customer, commodity price fluctuations. Enable has attempted toprices, heating and cooling degree days, environmental impacts, safety factors, system reliability and customer satisfaction.

CenterPoint Energy and CERC have weather normalization or other rate mechanisms that largely mitigate the impact of commodity pricesweather on Natural Gas in Indiana, Louisiana, Mississippi, Minnesota and Ohio, as applicable. CenterPoint Energy’s and CERC’s Natural Gas in Texas and CenterPoint Energy’s electric operations in Texas and Indiana do not have such mechanisms, although fixed customer charges are historically higher in Texas for Natural Gas compared to its business by entering into hedges, focusing on contracting fee-based business and converting existing commodity-based contracts to fee-based contracts.

Enable’s long-term view is that natural gas and crude oil production in the U.S. will increase. Over the past several years, there has been a fundamental shift in U.S. natural gas and crude oil production towards tight gas formations and shale plays. Advancements in technology have allowed producers to efficiently extract natural gas and crude oil from these formations and plays.other jurisdictions. As a result, fluctuations from normal weather may have a positive or negative effect on CenterPoint Energy’s and CERC’s Natural Gas’ results in Texas and on CenterPoint Energy’s electric operations’ results in its Texas and Indiana service territories.

Each state has a unique economy and is driven by different industrial sectors. Our largest customers reflect the proven reservesdiversity in industries in the states across our footprint. For example, Houston Electric is largely concentrated in Houston, a diverse economy where a higher percentage of employment is tied to the energy sector relative to other regions of the country. Although the Houston area represents a large part of our customer base, we have a diverse customer base throughout the various states our utility businesses serve. In Minnesota, for instance, education and health services are the state’s largest sectors. Indiana and Ohio are impacted by changes in the Midwest economy in general and changes in particular industries concentrated in the Midwest such as automotive, feed and grain processing. Some industries are driven by population growth like education and health care, while others may be influenced by strength in the national or international economy. Adverse economic conditions, coupled with concerns for protecting the environment and increased availability of alternate energy sources, may cause consumers to use less energy or avoid expansions of their facilities, including natural gas facilities, resulting in less demand for our services. Long-term national trends indicate customers have reduced their energy consumption, which could adversely affect our results. To the extent population growth is affected by lower energy prices and there is financial pressure on some of our customers who operate within the energy industry, there may be an impact on the growth rate of our customer base and overall demand. Management expects residential meter growth for Houston Electric to remain in line with long term trends at approximately 2%. Typical customer growth in the jurisdictions served by the Natural Gas reportable segment is approximately 1%. Management expects residential meter growth for CERC to remain in line with long term trends at approximately 1%.

Rising inflation and sustained high interest rates and a recessionary environment could potentially adversely impact CenterPoint Energy’s ability to execute on its 10-year capital plan. The inability to execute on our capital plan may result in lost
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future revenues for CenterPoint Energy. Additionally, these economic conditions may affect customers’ ability to pay their utility bills which may preclude our ability to collect balances due from such customers.

Further, the global supply chain has experienced significant disruptions due to a multitude of factors, such as labor shortages, resource availability, long lead times, inflation and weather. These disruptions have adversely impacted the utility industry. Like many of our peers, we have experienced disruptions to our supply chain and may continue to experience such disruptions in the future. To the extent adverse economic conditions, including supply chain disruptions, affect our suppliers and customers as well as our ability to meet our capital plan and generation transition plan, results from our energy delivery businesses may suffer. For more information, see Note 15 to the consolidated financial statements.

Further, in response to concerns for protecting the environment, we have strived to take a leading stance in the transition to safer and cleaner energy by being the first combined electric and natural gas utility with regulated generation assets to adopt net zero for its Scope 1 and certain Scope 2 GHG emissions by 2035 goals. In addition, we set a Scope 3 GHG emission reduction goal across our multi-state footprint by committing to help our residential and commercial customers reduce GHG emissions attributable to their end use of natural gas and crude oil in the U.S. have significantly increased.by 20% to 30% by 2035 from a 2021 baseline. Our capital plan supports these goals.


Natural gas continues to be a critical component of energy demand in the U.S. Over the long term, Enable’s management believes that the prospects for continued natural gas demand are favorable and will be driven by population and economic growth, as well as the continued displacement of coal-fired power plants by natural gas-fired power plants due to the price of natural gas and stricter government environmental regulations on the mining and burning of coal. Enable’s management believes that increasing consumption of natural gas over the long term in these sectors will continue to drive demand for Enable’s natural gas gathering, processing, transportation and storage services.

Enable may access the capital markets to fund its expansion capital expenditures. Historically, unit prices of midstream master limited partnerships have experienced periods of volatility. In addition, because Enable’s common units are yield-based securities,


rising market interest rates could impact the relative attractiveness of Enable’s common units to investors. Further, fluctuations in energy and commodity prices can create volatility in Enable’s common unit prices, which could impact investor appetite for its common units. Volatility in energy and commodity prices, as well as other macro-economic factors could impact the relative attractiveness of Enable’s debt securities to investors. As a result of capital market volatility, Enable may be unable to issue equity securities or debt on satisfactory terms, or at all, which may limit its ability to expand its operations or make future acquisitions.

The regulation of gathering and transmission pipelines, storage and related facilities by FERC and other federal and state regulatory agencies, including the DOT, has a significant impact on Enable’s business. For example, the DOT’s PHMSA has established pipeline integrity management programs that require more frequent inspections of pipeline facilities and other preventative measures, which may increase Enable’s compliance costs and increase the time it takes to obtain required permits. Additionally, increased regulation of oil and natural gas producers, including regulation associated with hydraulic fracturing, could reduce regional supply of oil and natural gas and therefore throughput on Enable’s gathering systems.

Enable relies on certain key natural gas producer customers for a significant portion of its natural gas and NGLs supply. For the year ended December 31, 2017, Enable’s top ten natural gas producer customers accounted for approximately 70% of its gathered volumes. These customers include affiliates of Continental, Vine, GeoSouthern, XTO Energy, Tapstone Energy, Apache, BP Energy Company, Chesapeake, Covey Park and Four Point Energy. Further, Enable relies on certain key utilities and producers for a significant portion of its transportation and storage demand. For the year ended December 31, 2017, Enable’s top transportation and storage customers by revenue were our affiliates and affiliates of Spire, American Electric Power Company, OGE, Continental, XTO Energy, Chesapeake, Midcontinent Express Pipeline, Entergy and Shell.

Enable is exposed to certain credit risks relating to its ongoing business operations. Credit risk includes the risk that counterparties that owe Enable money or commodities will breach their obligations. If the counterparties to these arrangements fail to perform, Enable may be forced to enter into alternative arrangements. In that event, Enable’s financial results could be adversely affected, and Enable could incur losses. Enable examines the creditworthiness of third-party customers to whom it extends credit and manages its exposure to credit risk through credit analysis, credit approval, credit limits and monitoring procedures, and for certain transactions, Enable may request letters of credit, prepayments or guarantees or seek to renegotiate its contract to reduce credit exposure.

Significant Events


Tax Reform. Series A Preferred Stock Redemption. On December 22, 2017, President Trump signed into law comprehensive tax reform legislation informally called The Tax Cuts and Jobs Acts, or TCJA, which resulted in significant changes to federal tax laws effective JanuarySeptember 1, 2018.  For the impacts2023, CenterPoint Energy redeemed all of the tax reform legislation, see Note 14outstanding shares of Series A Preferred Stock for cash of $800 million at a redemption price of $1,000 per share, plus accumulated and unpaid dividends thereon to, our consolidated financial statements.

Hurricane Harvey. Houston Electric’s electric delivery system and CERC Corp.’s NGD suffered damage as a result of Hurricane Harvey, which struckbut excluding, the Texas coast on Friday, August 25, 2017.redemption date. For further information, regarding the impact of Hurricane Harvey, see Note 612 to ourthe consolidated financial statements.


Brazos Valley Connection Project.Divestiture of Energy Systems Group.On May 21, 2023, Vectren Energy Services entered into an Equity Purchase Agreement to sell all of the outstanding limited liability company interests of Energy Systems Group to ESG Holdings Group, for a purchase price of $157 million, subject to customary adjustments set forth in the Equity Purchase Agreement, including adjustments based on Energy Systems Group’s net working capital at closing, indebtedness, cash and cash equivalents and transaction expenses. The transaction closed on June 30, 2023 for $154 million in cash, subject to finalization of the purchase price adjustment. For further information, see Note 4 to the consolidated financial statements.

Regulatory Proceedings. On March 23, 2023, CenterPoint Energy and CERC, collectively, received approximately $1.1 billion in proceeds from the customer rate relief bonds issued by the Texas Public Financing Authority related to the February 2021 Winter Storm Event.

On April 5, 2023, a final order was issued approving the $39 million revenue requirement from Houston Electric’s 2021 investment in TEEEF. On April 5, 2023, Houston Electric began constructionfiled its second TEEEF filing requesting a TEEEF revenue requirement of $188 million or a net increase in TEEEF revenues of approximately $149 million. On August 28, 2023 the State Office of Administrative Hearings issued an Order setting interim rates to collect an annual revenue requirement at the filed amount. On September 26, 2023, intervenors filed testimony with various recommendations including extending the amortization period. A settlement was reached with parties that incorporated an 8 1/2 year amortization period and a TEEEF revenue requirement of $153 million based on the Brazos Valley ConnectionDecember 31, 2022 balance with interim rates effective December 15, 2023. The State Office of Administrative Hearings ALJ approved the revised interim rates and the settlement was approved by the PUCT in its order issued on February 2017. 1, 2024.

On June 29, 2023, Indiana Electric received the net securitization proceeds of $337 million from the issuance and sale of the SIGECO Securitization Bonds to reimburse or pay for qualified costs approved by the IURC related to the completed retirement of its A.B. Brown coal-fired generation facilities.

For further details,information, see “—Liquidity and Capital Resources —Regulatory Matters —Brazos Valley Connection Project” below.

Bailey-Jones Creek Project. In April 2017, Houston Electric submitted a proposalNote 7 to ERCOT for an approximately $250 million transmission project in the greater Freeport, Texas area.consolidated financial statements. For further details, see “—Liquidity and Capital Resources —Regulatory Matters — Bailey-Jones Creek Project” below.

Regulatory Proceedings. For detailsinformation related to our pending and completed regulatory proceedings during 2017,to date in 2023 and to date in 2024, see “—Liquidity and Capital Resources —Regulatory Matters” below.


Debt Transactions. In 2017, we and CERC Corp. retired2023, CenterPoint Energy issued or redeemedborrowed a combined $800$6.0 billion in new debt, including Houston Electric’s issuance of $1.4 billion aggregate principal amount of general mortgage bonds, CERC’s issuance of $1.5 billion aggregate principal amount of senior notes and a $500 million term loan, SIGECO Securitization Subsidiary’s issuance of $341 million aggregate principal amount of SIGECO Securitization Bonds, SIGECO’s issuance of $650 million aggregate principal amount of first mortgage bonds, and CenterPoint Energy’s issuance of $1.0 billion aggregate principal amount of convertible senior notes, $400 million aggregate principal amount of senior notes. Additionally, we issued $500notes and a $250 million aggregate principal amountterm loan. During 2023, CenterPoint Energy repaid or redeemed a combined $3.0 billion of unsecureddebt, including CERC’s repayment of $1.0 billion of term loans and $1.332 billion of senior notes CERC Corp. issued $300maturing in 2023, CenterPoint Energy’s repayment of its
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$250 million aggregate principal amountterm loan and $350 million of unsecuredits floating rate senior notes and Houston Electric issued $300SIGECO’s early redemption of $91 million aggregateof first mortgage bonds, excluding scheduled principal amount of general mortgage bonds.payments on Securitization Bonds. For further information about our 2017 debt transactions in 2023, see Note 13 to ourthe consolidated financial statements.


Credit Facilities. In June 2017, CenterPoint Energy Houston ElectricLeadership Transition. On March 15, 2023, CenterPoint Energy announced the appointment of Christopher A. Foster to the position of Executive Vice President and CERC Corp. each entered into amendmentsChief Financial Officer, effective May 5, 2023. On September 27, 2023, CenterPoint Energy appointed Kristie L. Colvin to their respective revolving credit facilities to (a) extend the termination dateposition of Senior Vice President and terminate the swingline loan subfacility under each facility, and (b) for theChief Accounting Officer of CenterPoint Energy and its affiliated subsidiaries, effective October 5, 2023. On October 26, 2023, CenterPoint Energy announced the retirement of Dave Lesar and appointment of Jason Wells to the position of President and Chief Executive Officer, effective January 5, 2024.

Subsequent Events. On January 10, 2024, CenterPoint Energy entered into an Equity Distribution Agreement with certain financial institutions with respect to the offering and sale from time to time of shares of Common Stock, having an aggregate gross sales price of up to $500 million. Sales of Common Stock may be made by any method permitted by applicable law and deemed to be an “at the market offering” as defined in Rule 415 of the Securities Act of 1933. CenterPoint Energy may also enter into one or more forward sales agreements pursuant to master forward confirmations. The offer and sale of Common Stock under the Equity Distribution Agreement will terminate upon the earliest of (1) the sale of all Common Stock subject to the Equity Distribution Agreement, (2) termination of the Equity Distribution Agreement, or (3) May 17, 2026.As of February 20, 2024, CenterPoint Energy has not issued any shares of Common Stock under the Equity Distribution Agreement and has not entered into any forward sale agreements.

Additionally, on February 19, 2024, CenterPoint Energy, through its subsidiary CERC Corp. facilities, increase, entered into the aggregate commitments under such facilities.LAMS Asset Purchase Agreement to sell its Louisiana and Mississippi natural gas local distribution company businesses. The transaction is expected to close in the first quarter of 2025. For further information, about our 2017 credit facility amendments, see Note 1321 to ourthe consolidated financial statements.




AEM Acquisition. In January 2017, CES acquired AEM. For more information regarding this acquisition, see Note 4 to our consolidated financial statements.

CERTAIN FACTORS AFFECTING FUTURE EARNINGS


Our past earnings and results of operations are not necessarily indicative of our future earnings and results of operations. The magnitude of our and Enable’s future earnings and results of our and Enable’s operations will depend on or be affected by numerous factors that apply to all Registrants unless otherwise indicated including:


•CenterPoint Energy’s business strategies and strategic initiatives, restructurings, including the performancecompleted Restructuring, joint ventures and acquisitions or dispositions of Enable,assets or businesses, including the amountproposed sale of cash distributions we receive from Enable, Enable’s ability to redeem the Series A Preferred Units in certain circumstancesour Louisiana and Mississippi natural gas local distribution company businesses, and the valuecompleted sale of our interest in Enable, and factors that mayEnergy Systems Group, which we cannot assure will have a material impact on such performance, cash distributions and value, including factors such as:the anticipated benefits to us;

◦competitive conditions in the midstream industry, and actions taken by Enable’s customers and competitors, including the extent and timing of the entry of additional competition in the markets served by Enable;

◦the timing and extent of changes in the supply of natural gas and associated commodity prices, particularly prices of natural gas and NGLs, the competitive effects of the available pipeline capacity in the regions served by Enable, and the effects of geographic and seasonal commodity price differentials, including the effects of these circumstances on re-contracting available capacity on Enable’s interstate pipelines;

◦the demand for crude oil, natural gas, NGLs and transportation and storage services;

◦environmental and other governmental regulations, including the availability of drilling permits and the regulation of hydraulic fracturing;

◦recording of non-cash goodwill, long-lived asset or other than temporary impairment charges by or related to Enable;

◦changes in tax status;

◦access to debt and equity capital; and

◦the availability and prices of raw materials and services for current and future construction projects;

•industrial, commercial and residential growth in our service territories and changes in market demand, including the effects of energy efficiency measures and demographic patterns;

•our ability to fund and invest planned capital and the timely recovery of our investments, including those related to Indiana Electric’s generation transition plan as part of its IRPs;
•our ability to successfully construct, operate, repair and maintain electric generating facilities, natural gas facilities, TEEEF and electric transmission facilities, including complying with applicable environmental standards and the implementation of a well-balanced energy and resource mix, as appropriate;
•timely and appropriate rate actions that allow and authorize requested and timely recovery of costs and a reasonable return on investment;investment, including the timing and amount of recovery of Houston Electric’s TEEEF leases, and requested or favorable adjustments to rates and approval of other requested items as part of base rate proceedings;

future •economic conditions in regional and national markets, including changes to inflation and interest rates, and instability of banking institutions, and their effect on sales, prices and costs;

•weather variations and other natural phenomena, including the impact of severe weather events on operations, capital and capital;legislation such as in connection with the February 2021 Winter Storm Event;

•volatility in the markets for natural gas as a result of, among other factors, armed conflicts, including the conflict in the Middle East and any broader related conflict, and the conflict in Ukraine, and the related sanctions on certain Russian entities;
•disruptions to the global supply chain, including volatility in commodity prices, and tariffs and other legislation impacting the supply chain, that could prevent CenterPoint Energy from securing the resources needed to, among other things, fully execute on its 10-year capital plan or achieve its net zero and carbon emissions reduction goals;
•non-payment for our services due to financial distress of our customers and the ability of our customers, including REPs, to satisfy their obligations to CenterPoint Energy, Houston Electric and CERC, and the negative impact on such ability related to adverse economic conditions and severe weather events;
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•public health threats, such as COVID-19, and their effect on our operations, business and financial condition, our industries and the communities we serve, U.S. and world financial markets and supply chains, potential regulatory actions and changes in customer and stakeholder behavior relating thereto;
•state and federal legislative and regulatory actions or developments affecting various aspects of our businesses, (including the businesses of Enable), including, among others, energy deregulation or re-regulation, pipeline integrity and safety and changes in regulation and legislation pertaining to trade, health care, finance and actions regarding the rates charged by our regulated businesses;

•direct or indirect effects on our facilities, resources, operations and financial condition resulting from terrorism, cyberattacks or intrusions, data security breaches or other attempts to disrupt our businesses or the businesses of third parties, or other catastrophic events such as fires, ice, earthquakes, explosions, leaks, floods, droughts, hurricanes, tornadoes and other severe weather events, pandemic health events or other occurrences;
•tax reform and legislation, including the effects of the TCJAIRA (which includes but is not limited to any potential changes to tax rates, CAMT imposed, tax credits and/or interest deductibility), as well as any changes in tax laws under the current or future administrations, and uncertainties involving state commissions’ and local municipalities’ regulatory requirements and determinations regarding the treatment of EDIT and our rates;

•our ability to mitigate weather impacts through normalization or rate mechanisms, and the effectiveness of such mechanisms;

•actions by credit rating agencies, including any potential downgrades to credit ratings;
the timing and extent of changes in commodity prices, particularly natural gas, and the effects of geographic and seasonal commodity price differentials;

problems with•matters affecting regulatory approval, legislative actions, construction, implementation of necessary technology or other issues with respect to major capital projects that result in delays or cancellation or in cost overrunscosts that cannot be recouped in rates;

•local, state and federal legislative and regulatory actions or developments relating to the environment, including, among others, those related to global climate change;change, air emissions, carbon, waste water discharges and the handling and disposal of CCR that could impact operations, cost recovery of generation plant costs and related assets, and CenterPoint Energy’s net zero and carbon emissions reduction goals;

•the impact of unplanned facility outages;

any direct or indirect effects on our or Enable’s facilities, operations and financial condition resulting from terrorism, cyber-attacks, data security breachesoutages or other attempts to disrupt our businesses or the businesses of third parties, or otherclosures;


catastrophic events such as fires, earthquakes, explosions, leaks, floods, droughts, hurricanes, pandemic health events or other occurrences;

our ability to invest planned capital and the timely recovery of our investment in capital;

our ability to control operation and maintenance costs;

actions by credit rating agencies;

•the sufficiency of our insurance coverage, including availability, cost, coverage and terms;terms and ability to recover claims;

•the availability and prices of raw materials and services and changes in labor for current and future construction projects and operations and maintenance costs, including our ability to control such costs;
the investment performance of our•impacts from CenterPoint Energy’s pension and postretirement benefit plans;plans, such as the investment performance and increases to net periodic costs as a result of plan settlements and changes in assumptions, including discount rates;

•changes in interest rates and their impact on costs of borrowing and the valuation of CenterPoint Energy’s pension benefit obligation;
•commercial bank and financial market conditions, including disruptions in the banking industry, our access to capital, the cost of such capital, and the results of our financing and refinancing efforts, including availability of funds in the debt capital markets;

changes in interest rates and their impact on our costs of borrowing and the valuation of our pension benefit obligation;

changes in rates of inflation;

•inability of various counterparties to meet their obligations to us;

non-payment for our services due to financial distress of our customers;

•the extent and effectiveness of our risk management and hedging activities, including, but not limited to our financial and weather hedges;activities;

•timely and appropriate regulatory actions, which include actions allowing securitization for any future hurricanes or other severe weather events, or natural disasters or other recovery of costs, including costs associated with Hurricane Harvey;stranded coal-fired generation asset costs;

our or Enable’s potential business strategies and strategic initiatives, including restructurings, joint ventures and acquisitions or dispositions of assets or businesses (including a reduction of our interests in Enable, if any; whether through our decision to sell all or a portion of the Enable common units we own in the public equity markets or otherwise, subject to certain limitations), which we cannot assure you will be completed or will have the anticipated benefits to us or Enable;

•acquisition and merger or divestiture activities involving us or our competitors;

our or Enable’sindustry, including the ability to recruit,successfully complete merger, acquisition and divestiture plans such as the proposed sale of our Louisiana and Mississippi natural gas local distribution company businesses;
•our ability to attract, effectively transition, motivate and retain management and key employees and maintain good labor relations;

the ability of GenOn (formerly known as RRI Energy, Inc., Reliant Energy and RRI), a wholly-owned subsidiary of NRG, and its subsidiaries, currently the subject of bankruptcy proceedings, to satisfy their obligations to us, including indemnity obligations;

the outcome of litigation;

the ability of REPs, including REP affiliates of NRG and Vistra Energy Corp., formerly known as TCEH Corp., to satisfy their obligations to us and our subsidiaries;

•changes in technology, particularly with respect to efficient battery storage or the emergence or growth of new, developing or alternative sources of generation;generation, and their adoption by consumers;

•the impact of climate change and alternate energy sources on the demand for natural gas and electricity generated or transmitted by us;
•the timing and outcome of any audits, disputes and other proceedings related to taxes;

•the recording of impairment charges;
•political and economic developments, including energy and environmental policies under the effective tax rates;current administration;

•CenterPoint Energy’s ability to execute on its strategy, initiatives, targets and goals, including its net zero and carbon emissions reduction goals and its operations and maintenance expenditure goals;
•the outcome of litigation, including litigation related to the February 2021 Winter Storm Event;
•the effect of changes in and application of accounting standards and pronouncements; and

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•other factors we discuss underdiscussed in “Risk Factors” in Item 1A of Part I of this report and in other reports wethat the Registrants file from time to time with the SEC.




CENTERPOINT ENERGY CONSOLIDATED RESULTS OF OPERATIONS

 Year Ended December 31,
 2017 2016 2015
 (in millions, except per share amounts)
Revenues$9,614
 $7,528
 $7,386
Expenses8,542
 6,569
 6,453
Operating Income1,072
 959
 933
Gain (Loss) on Marketable Securities7
 326
 (93)
Gain (Loss) on Indexed Debt Securities49
 (413) 74
Interest and Other Finance Charges(313) (338) (352)
Interest on Securitization Bonds(77) (91) (105)
Equity in Earnings (Losses) of Unconsolidated Affiliates265
 208
 (1,633)
Other Income, net60
 35
 46
Income (Loss) Before Income Taxes1,063
 686
 (1,130)
Income Tax Expense (Benefit)(729) 254
 (438)
Net Income (Loss)$1,792
 $432
 $(692)
      
Basic Earnings (Loss) Per Share$4.16
 $1.00
 $(1.61)
      
Diluted Earnings (Loss) Per Share$4.13
 $1.00
 $(1.61)

2017 Compared to 2016

Net Income.  We reported net incomeCenterPoint Energy’s results of $1,792 million ($4.13 per diluted share)operations are affected by seasonal fluctuations in the demand for 2017 compared to net incomeelectricity and natural gas. CenterPoint Energy’s results of $432 million ($1.00 per diluted share) for 2016.

The increase in net incomeoperations are also affected by, among other things, the actions of $1,360 million was primarily due to the following key factors:

a $983 million decrease invarious governmental authorities having jurisdiction over rates its subsidiaries charge, debt service costs, income tax expense, resultingits subsidiaries ability to collect receivables from a reduction in income tax expenseREPs and customers and its ability to recover its regulatory assets. For information regarding factors that may affect the future results of $1,113 million due to tax reform, discussed further in Note 14 to our consolidated financial statements, offset by a $130 million increaseoperations, please read “Risk Factors” in income tax expense primarily dueItem 1A of Part I of this report.

Income available to higher net income year over year;

a $462 million increase in gains on indexed debt securities related to the ZENS, resulting from increased gains of $345 million in the underlying value of the indexed debt securities and a loss of $117 million from the Charter merger in 2016;

a $113 million increase in operating income discussed below by segment;

a $57 million increase in equity earnings from our investment in Enable, discussed further in Note 10 to our consolidated financial statements;

a $25 million decrease in interest expense due to lower weighted average interest rates on outstanding debt;

a $17 million decrease in losses on early debt redemption;

a $14 million increase in cash distributions on Series A Preferred Units included in Other Income, net shown above; and

a $14 million decrease in interest expense related to lower outstanding balances of our Securitization Bonds.

These increases were partially offset by:

• a $319 million decrease in gains on marketable securities; and

•a $6 million decrease in miscellaneous other non-operating income included in Other Income, net shown above.



Income Tax Expense. We reported an effective tax rate of (69%) and 37%common shareholders for the years ended December 31, 20172023, 2022 and 2016, respectively. The effective tax rate2021 was as follows:
Year Ended December 31,Favorable (Unfavorable)
2023202220212023 to 20222022 to 2021
(in millions)
Electric$654 $603 $475 $51 $128 
Natural Gas533 492 403 41 89 
Total Utility Operations1,187 1,095 878 92 217 
Corporate & Other (1)
(320)(87)(305)(233)218 
Discontinued Operations— — 818 — (818)
  Total CenterPoint Energy$867 $1,008 $1,391 $(141)$(383)

(1)Includes energy performance contracting and sustainable infrastructure services through Energy Systems Group through the date of (69%) is primarily duesale on June 30, 2023, unallocated corporate costs, interest income and interest expense, intercompany eliminations and the reduction of income allocated to the remeasurement of our ADFIT liability as a result of the enactment of the TCJA on December 22, 2017, which reduced the U.S. corporate income tax rate from 35% to 21%. See Note 14 to our consolidated financial statements for a more in depth discussion of the 2017 impacts of the TCJA.preferred shareholders.


20162023 Compared to 20152022


Net Income.  We  CenterPoint Energy reported net income available to common shareholders of $432$867 million ($1.00 per diluted share) for 20162023 compared to a net lossincome available to common shareholders of $692$1,008 million ($(1.61) per diluted share) for the same period in 2015.2022.


The increase in net income of $1,124 million was dueIncome available to the following key factors:

a $1,841 million increase in equity earnings from our investment in Enable, as 2015 results included impairment charges of $1,846 million, discussed further in Note 10 to our consolidated financial statements;

a $419 million increase in the gain on our marketable securities;

a $26 million increase in operating income discussed below by segment;

a $22 million increase in cash distributions on Series A Preferred Units included in Other Income, net shown above;

a $14 million decrease in interest expense due to lower weighted average interest rates on outstanding debt; and

a $14 million decrease in interest expense related to lower outstanding balances of our Securitization Bonds.

These increases were partially offset by:

a $692 million increase in income tax expense due to higher income before tax;

a $487 million increase in the loss on indexed debt securities related to the ZENS resulting from a loss of $117 million from the Charter merger in 2016 compared to a loss of $7 million from Verizon’s acquisition of AOL in 2015 and increased losses of $377 million in the underlying value of the indexed debt securities;

a $22 million loss on early redemption of our $300 million 6.5% senior notes otherwise due 2018 included in Other Income, net shown above;

a $6 million decrease in interest income due primarily to Enable’s repayment of $363 million note payable to us included in Other Income, net shown above; and

a $5 million decrease in miscellaneous other non-operating income include in Other Income, net shown above.

Income Tax Expense.  We reported an effective tax rate of 37% and 39% for the years ended December 31, 2016 and 2015, respectively. The effective tax rate of 39% is primarily due to lower earnings from the impairment of our investment in Enable. The impairment loss reduced the deferred tax liability on our investment in Enable.



RESULTS OF OPERATIONS BY BUSINESS SEGMENT

The following table presents operating income for each of our business segments for 2017, 2016 and 2015. Included in revenues are intersegment sales. We account for intersegment sales as if the sales were to third parties at current market prices.

Operating Income by Business Segment
 Year Ended December 31,
 2017 2016 2015
 (in millions)
Electric Transmission & Distribution$610
 $628
 $607
Natural Gas Distribution328
 303
 273
Energy Services125
 20
 42
Other Operations9
 8
 11
Total Consolidated Operating Income$1,072
 $959
 $933

Electric Transmission & Distribution

The following tables provide summary data of our Electric Transmission & Distribution business segment for 2017, 2016 and 2015:
 Year Ended December 31,
 2017 2016 2015
Revenues:(in millions, except throughput and customer data)
TDU$2,588
 $2,507
 $2,364
Bond Companies409
 553
 481
Total revenues2,997
 3,060
 2,845
Expenses: 
  
  
Operation and maintenance, excluding Bond Companies1,423
 1,355
 1,300
Depreciation and amortization, excluding Bond Companies395
 384
 340
Taxes other than income taxes235
 231
 222
Bond Companies334
 462
 376
Total expenses2,387
 2,432
 2,238
Operating Income$610
 $628
 $607
Operating Income:   
  
TDU$535
 $537
 $502
Bond Companies (1) 
75
 91
 105
Total segment operating income$610
 $628
 $607
Throughput (in GWh): 
  
  
Residential29,703
 29,586
 28,995
Total88,636
 86,829
 84,191
Number of metered customers at end of period: 
  
  
Residential2,164,073
 2,129,773
 2,079,899
Total2,444,299
 2,403,340
 2,348,517

(1)Represents the amount necessary to pay interest on the Securitization Bonds.

2017 Compared to 2016.  Our Electric Transmission & Distribution business segment reported operating income of $610 million for 2017, consisting of $535 million from the TDU and $75 million related to the Bond Companies. For 2016, operating income totaled $628 million, consisting of $537 million from the TDU and $91 million related to the Bond Companies.



TDU operating incomecommon shareholders decreased $2$141 million primarily due to the following key factors:items:


lower equity return•an increase in net income of $22$51 million primarily relatedfor the Electric reportable segment, as further discussed below;
•an increase in net income of $41 million for the Natural Gas reportable segment, as further discussed below; and
•a decrease in income available to the annual true-upcommon shareholders of transition charges correcting$233 million for over-collections that occurred during the preceding 12 months;

higher depreciation, primarily because of ongoing additions to plant in service,Corporate and other taxes of $20 million;

higher operation and maintenance expenses of $19 million,Other, primarily due to higher labor and benefits costsa pre-tax net gain of $10$86 million and corporate support services expenseson the sale of $8 million;

lower usage of $15 million; and

•lower miscellaneous revenues, including right-of-way, of $10 million.

These decreasesEnergy Transfer equity securities in 2022 further discussed in Note 11 to operating income werethe consolidated financial statements, partially offset by the following:

rate increases$45 million of $47costs associated with early redemption of long-term debt in first quarter 2022. The decrease is also due to a loss on sale of $13 million related to distribution capital investments;

•customer growthand current tax expense of $32 million from the addition of almost 41,000 customers; and

higher transmission-related revenues of $61 million, partially offset by transmission costs billed by transmission providers of $56 million.
2016 Compared to 2015.  Our Electric Transmission & Distribution business segment reported operating income of $628 million for 2016, consisting of $537 million from the TDU and $91 million related to the Bond Companies. For 2015, operating income totaled $607 million, consistingdivestiture of $502 million from the TDU and $105 million relatedEnergy Systems Group further discussed in Note 4 to the Bond Companies.

TDU operating income increased $35consolidated financial statements, as well as $19 million due to the following key factors:remeasurement of deferred income tax balances. The remaining variance is due largely to an increase in borrowing costs.


•customer growth2022 Compared to 2021

Net Income.  CenterPoint Energy reported income available to common shareholders of $31$1,008 million from the additionfor 2022 compared to income available to common shareholders of over 54,000 customers;$1,391 million for 2021.


higher transmission-related revenues of $82 million, partially offset by transmission costs billed by transmission providers of $55 million;

higher equity return of $17Income available to common shareholders decreased $383 million primarily due to the annual true-upfollowing items:

•an increase in net income of transition charges correcting$128 million for under-collections that occurred during the preceding 12 months;Electric reportable segment, as further discussed below;
•an increase in net income of $89 million for the Natural Gas reportable segment, as further discussed below;
•an increase in income available to common shareholders of $218 million for Corporate and

•rate increases of $13 Other, primarily due to a $28 million pre-tax payment related to distribution capital investments.

These increasesthe impact of Board-implemented governance changes announced in July 2021, the net gain of $86 million in 2022 and a net loss of $122 million in December 2021 on the sale of Energy Transfer equity securities discussed further in Note 11 to operating income werethe consolidated financial statements, partially offset by a $34 million loss in Enable Series A Preferred Unit distributions in 2021 discussed in Note 4, and a decrease in income allocated to
50

preferred shareholders of $46 million, primarily due to the following:conversion of the Series B Preferred Stock to Common Stock during 2021; and

•a decrease in income of $818 million from discontinued operations, discussed further in Note 4 to the consolidated financial statements.
higher depreciation, primarily because
Income Tax Expense. For a discussion of ongoing additionseffective tax rate per period, see Note 14 to plantthe consolidated financial statements.

Subsequent Events. 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 local distribution company businesses. The transaction is expected to close in service,the first quarter of 2025. For further information, see Note 21 to the consolidated financial statements.


51

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 other taxesexpense, which may result in inter-segment profit and loss.

The following discussion of $45 million;CenterPoint Energy’s results of operations is separated into two reportable segments, Electric and Natural Gas.


•higher operation and maintenance expenses of $3 million; andELECTRIC

•lower right-of-way revenues of $3 million.




Natural Gas Distribution


The following table provides summary data of our Natural Gas Distribution business segmentCenterPoint Energy’s Electric reportable segment:
 Year Ended December 31,Favorable (Unfavorable)
 2023202220212023 to 20222022 to 2021
(in millions, except throughput, weather and customer data)
Revenues$4,290 $4,108 $3,763 $182 $345 
Expenses:   
Utility natural gas, fuel and purchased power176 222 186 46 (36)
Operation and maintenance1,880 1,864 1,761 (16)(103)
Depreciation and amortization872 793 775 (79)(18)
Taxes other than income taxes272 275 268 3 (7)
Total expenses3,200 3,154 2,990 (46)(164)
Operating Income1,090 954 773 136 181 
Other Income (Expense):
Interest expense and other finance charges(303)(235)(226)(68)(9)
Other income (expense), net56 31 23 25 8 
Income before income taxes843 750 570 93 180 
Income tax expense189 147 95 (42)(52)
Net income$654 $603 $475 $51 $128 
Throughput (in GWh):   
Residential35,166 35,074 32,067 — %9 %
Total108,766 105,541 103,000 3 %2 %
Weather (percentage of normal weather for service area):
Cooling degree days114 %110 %108 %4 %2 %
Heating degree days90 %121 %82 %(31)%39 %
Number of metered customers at end of period:   
Residential2,588,510 2,534,730 2,493,832 2 %2 %
Total2,916,028 2,858,203 2,814,859 2 %2 %


52


The following table provides variance explanations by major income statement caption for 2017, 2016 and 2015: the Electric reportable segment:
Favorable (Unfavorable)
2023 to 20222022 to 2021
(in millions)
Revenues
Customer rates and impact of the change in rate design$167 $38 
Transmission Revenues, including TCOS and TCRF and impact of the change in rate design, inclusive of costs billed by transmission providers, partially offset in operation and maintenance below122 157 
Customer growth26 28 
Refund of protected and unprotected EDIT, offset in income tax expense— 32 
Impacts from increased peak demand in the prior year, collected in rates in the current year— 2 
Energy efficiency, partially offset in operation and maintenance below— (3)
Equity return, related to the annual true-up of transition charges for amounts over or under collected in prior periods(5)2 
Pass-through revenues, offset in operation and maintenance below(13)21 
Miscellaneous revenues, primarily related to service connections and off-system sales(14)11 
Bond Companies and SIGECO Securitization Subsidiary, offset in other line items below(27)(33)
Weather, efficiency improvements and other usage impacts(28)54 
Cost of fuel and purchased power, offset in utility natural gas, fuel and purchased power below(46)36 
Total$182 $345 
Utility natural gas, fuel and purchased power
Cost of purchased power, offset in revenues above$30 $12 
Cost of fuel, including coal, natural gas, and fuel oil, offset in revenues above16 (48)
$46 $(36)
Operation and maintenance
Transmission costs billed by transmission providers, offset in revenues above$(26)$(77)
Contract services(21)(2)
Energy efficiency, offset in revenues above(8)4 
Support services(8)20 
Bond Companies and SIGECO Securitization Subsidiary, offset in other line items— 3 
Labor and benefits7 7 
Pass through expenses, offset in revenues above11 (19)
All other operation and maintenance expense, including materials and supplies and insurance29 (39)
Total$(16)$(103)
Depreciation and amortization
Ongoing additions to plant-in-service$(106)$(40)
Bond Companies and SIGECO Securitization Subsidiary, offset in other line items27 22 
Total$(79)$(18)
Taxes other than income taxes
Incremental capital projects placed in service, and the impact of changes to tax rates$2 $(14)
Franchise fees and other taxes1 7 
Total$3 $(7)
Interest expense and other finance charges
Changes in outstanding debt$(76)$(32)
Bond Companies and SIGECO Securitization Subsidiary, offset in other line items above(4)8 
Other, primarily AFUDC and impacts of regulatory deferrals12 15 
Total$(68)$(9)
Other income (expense), net
Other income, including AFUDC - equity$21 $8 
Bond Companies and SIGECO Securitization Subsidiary, offset in other line items above4 — 
Total$25 $8 

Income Tax Expense. For a discussion of effective tax rate per period by Registrant, see Note 14 to the consolidated financial statements.
53

 Year Ended December 31,
 2017 2016 2015
 (in millions, except throughput and customer data)
Revenues$2,639
 $2,409
 $2,632
Expenses: 
  
  
Natural gas1,164
 1,008
 1,297
Operation and maintenance742
 714
 697
Depreciation and amortization260
 242
 222
Taxes other than income taxes145
 142
 143
Total expenses2,311
 2,106
 2,359
Operating Income$328
 $303
 $273
Throughput (in Bcf):   
  
Residential151
 152
 171
Commercial and industrial261
 259
 262
Total Throughput412
 411
 433
Number of customers at end of period:   
  
Residential3,213,140
 3,183,538
 3,149,845
Commercial and industrial256,651
 255,806
 253,921
Total3,469,791
 3,439,344
 3,403,766

NATURAL GAS
2017 Compared to 2016.  Our Natural Gas Distribution business segment reported operating income of $328 million for 2017 compared to $303 million for 2016.

Operating income increased $25 million primarily as a result of the following key factors:

rate increases of $38 million, primarily from Texas rate filings of $14 million, Arkansas rate case and formula rate plan filings of $9 million, Minnesota interim rates of $7 million and Mississippi RRA of $4 million;

higher other revenues of $8 million, primarily driven by transportation revenues;

customer growth of $7 million from the addition of over 30,000 new customers;

labor and benefits were favorable by $5 million, resulting primarily from the recording of a regulatory asset (and a corresponding reduction in expense) to recover $16 million of prior postretirement expenses in future rates established in the Texas Gulf rate order; and

an increase of $7 million from weather normalization adjustments, partially offset by $4 million of milder weather effects.

These increases were partially offset by:

higher operation and maintenance expenses of $20 million, primarily due to increased bad debt expenses of $7 million, increased contract services of $7 million, increased insurance costs of $3 million and increased corporate support services expenses of $2 million; and

increased depreciation and amortization expense, primarily due to ongoing additions to plant-in-service, and other taxes of $16 million.

Increased operation and maintenance expense related to energy efficiency programs of $13 million and decreased other taxes expense related to gross receipt taxes of $5 million were offset by a corresponding increase or decrease in the related revenues.



2016 Compared to 2015.  Our Natural Gas Distribution business segment reported operating income of $303 million for 2016 compared to $273 million for 2015.

Operating income increased $30 million primarily as a result of the following key factors:

rate increases of $55 million, primarily from the 2015 Minnesota rate case, including the decoupling rider, and the Texas GRIP filing;

lower bad debt expense of $12 million resulting from lower customer bills due to warmerthan normal weather as well as credit and collections process improvements that have reduced write-offs;

an increase of $26 million from weather normalization adjustments, including weather-related decoupling and hedging activities, partially offset by $19 million of milder weather effects; and

customer growth of $5 million from the addition of over 35,000 new customers.

These increases were partially offset by:

increased depreciation and amortization of $20 million, primarily due to ongoing additions to plant in service;

higher labor and benefits expenses of $11 million, primarily driven by increased pension costs;

higher contract services expenses of $10 million, primarily for increased pipeline integrity, leak surveying and repair activities; and

increased operation and maintenance expenses of $8 million related to higher support services costs and other miscellaneous expenses.

Increased operation and maintenance expense related to energy efficiency programs of $1 million and decreased other taxes expense related to gross receipt taxes of $3 million were offset by a corresponding increase or decrease in the related revenues.

Energy Services


The following table provides summary data of ourCenterPoint Energy’s Natural Gas reportable segment:
Year Ended December 31,Favorable (Unfavorable)
2023202220212023 to 20222022 to 2021
(in millions, except throughput, weather and customer data)
Revenues$4,279 $4,946 $4,336 $(667)$610 
Expenses:
Utility natural gas, fuel and purchased power1,888 2,665 1,941 777 (724)
Non-utility cost of revenues, including natural gas3 4 18 1 14 
Operation and maintenance949 919 979 (30)60 
Depreciation and amortization513 466 527 (47)61 
Taxes other than income taxes245 261 253 16 (8)
Total expenses3,598 4,315 3,718 717 (597)
Operating Income681 631 618 50 13 
Other Income (Expense)
Gain on sale— 303 8 (303)295 
Interest expense and other finance charges(188)(137)(141)(51)4 
Other income (expense), net15 (62)(2)77 (60)
Income from Continuing Operations Before Income Taxes508 735 483 (227)252 
Income tax expense (benefit)(25)243 80 268 (163)
Net Income$533 $492 $403 $41 $89 
Throughput (in Bcf):
Residential199 240 241 (17)%— %
Commercial and industrial418 424 428 (1)%(1)%
Total Throughput617 664 669 (7)%(1)%
Weather (percentage of 10-year average for service area):
Heating degree days86 %106 %91 %(20)%15 %
Number of customers at end of period:
Residential4,010,113 3,964,221 4,372,428 1 %(9)%
Commercial and industrial303,841 301,834 354,602 1 %(15)%
Total4,313,954 4,266,055 4,727,030 1 %(10)%



54

The following table provides variance explanations by major income statement caption for the Natural Gas reportable segment:
Favorable (Unfavorable)
2023 to 20222022 to 2021
(in millions)
Revenues
Cost of natural gas, offset in utility natural gas, fuel and purchased power below$(754)$923 
Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale(38)(457)
Gross receipts tax, offset in taxes other than income taxes below(17)19 
Weather and usage(7)22 
Refund of protected and unprotected EDIT, offset in income tax expense3 6 
Non-volumetric and miscellaneous revenue14 26 
Energy efficiency and other pass-through, offset in operation and maintenance below17 3 
Non-utility revenues, including impacts of MES disposal18 (17)
Customer growth20 16 
Customer rates and impact of the change in rate design, exclusive of the TCJA impact below77 69 
Total$(667)$610 
Utility natural gas, fuel and purchased power
Cost of natural gas, offset in revenues above$754 $(923)
Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale23 199 
$777 $(724)
Non-utility costs of revenues, including natural gas
Non-utility cost of revenues, including natural gas$1 $14 
$1 $14 
Operation and maintenance
Miscellaneous operations and maintenance expenses, including bad debt expense$(36)$(21)
Energy efficiency and other pass-through, offset in revenues above(17)(3)
Contract services(3)(14)
Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale3 125 
Labor and benefits, primarily due to headcount11 (5)
Corporate support services12 (22)
Total$(30)$60 
Depreciation and amortization
Incremental capital projects placed in service$(49)$(23)
Lower depreciation rates in Indiana from 2021 rate order— 18 
Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale2 66 
Total$(47)$61 
Taxes other than income taxes
Gross receipts tax, offset in revenues above$17 $(19)
Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale1 23 
Incremental capital projects placed in service(2)(12)
Total$16 $(8)
Gain on Sale
Gain on Sale of Arkansas and Oklahoma Natural Gas businesses in 2022$(303)$295 
Total$(303)$295 
Interest expense and other finance charges
Changes in outstanding debt$(59)$(11)
Other, primarily AFUDC and impacts of regulatory deferrals8 15 
Total$(51)$4 
Other income (expense), net
Changes to non-service benefit cost, primarily settlement cost incurred in 2022$60 $(66)
AFUDC - Equity, primarily from increased capital spend10 3 
Other miscellaneous non-operating income (expenses)7 3 
Total$77 $(60)

Income Tax Expense (Benefit). For a discussion of effective tax rate per period by Registrant, see Note 14 to the consolidated financial statements.

55

Subsequent Events. On February 19, 2024, CenterPoint Energy, Services business segment for 2017, 2016through its subsidiary CERC Corp., entered into the LAMS Asset Purchase Agreement to sell its Louisiana and 2015:
 Year Ended December 31,
 2017 2016 2015
 (in millions, except throughput and customer data)
Revenues$4,049
 $2,099
 $1,957
Expenses: 
  
  
Natural gas3,816
 2,011
 1,867
Operation and maintenance87
 59
 42
Depreciation and amortization19
 7
 5
Taxes other than income taxes2
 2
 1
Total expenses3,924
 2,079
 1,915
Operating Income$125
 $20
 $42
      
Timing impacts related to mark-to-market gain (loss) (1)
$79
 $(21) $4
      
Throughput (in Bcf)1,200
 777
 618
      
Number of customers at end of period (2)
31,000
 30,000
 18,000

(1)Includes the change in unrealized mark-to-market value and the impact from derivative assets and liabilities acquired through the purchase of Continuum and AEM.


(2)These numbers do not include approximately 72,000 and 60,100 natural gas customers as of December 31, 2017 and 2016, respectively, that are under residential and small customer choice programs invoiced by their host utility.

2017 Compared to 2016. Our Energy Services business segment reported operating income of $125 million for 2017 compared to $20 million for 2016. The increase in operating income of $105 million was primarily due to a $100 million increase from mark-to-market accounting for derivatives associated with certainMississippi natural gas purchases and sales used to lock in economic margins. A weather-driven spike in natural gas prices at the end of 2017 caused the accrual of an unusually high mark-to-market asset,local distribution company businesses. The transaction is expected to be substantially reversedclose in the first quarter of 2018 as natural gas prices normalize. Operating income in 2017 also included approximately $5 million of expenses related2025. For further information, see Note 21 to the acquisitionconsolidated financial statements.

HOUSTON ELECTRIC CONSOLIDATED RESULTS OF OPERATIONS

Houston Electric’s CODM views net income as the measure of profit or loss for its reportable segment. Houston Electric consists of a single reportable segment. Houston Electric’s results of operations are affected by seasonal fluctuations in the demand for electricity. Houston Electric’s results of operations are also affected by, among other things, the actions of various governmental authorities having jurisdiction over rates Houston Electric charges, debt service costs, income tax expense, Houston Electric’s ability to collect receivables from REPs and integrationHouston Electric’s ability to recover its regulatory assets. For information regarding factors that may affect the future results of AEM. The remaining increaseHouston Electric’s consolidated operations, please read “Risk Factors” in operating income was primarily due to increased throughput related to the acquisitionItem 1A of AEM in 2017.Part I of this report.

 Year Ended December 31,Favorable (Unfavorable)
 2023202220212023 to 20222022 to 2021
(in millions, except throughput, weather and customer data)
Revenues:
TDU$3,514 $3,205 $2,894 $309 $311 
Bond Companies163 207 240 (44)(33)
Total revenues3,677 3,412 3,134 265 278 
Expenses:
Operation and maintenance, excluding Bond Companies1,669 1,647 1,591 (22)(56)
Depreciation and amortization, excluding Bond Companies593 479 429 (114)(50)
Taxes other than income taxes262 261 251 (1)(10)
Bond Companies159 194 219 35 25 
Total2,683 2,581 2,490 (102)(91)
Operating Income994 831 644 163 187 
Interest expense and other finance charges(259)(202)(183)(57)(19)
Interest expense on Securitization Bonds(8)(13)(21)5 8 
Other income, net34 19 17 15 2 
Income before income taxes761 635 457 126 178 
Income tax expense168 125 76 (43)(49)
Net income$593 $510 $381 $83 $129 
Throughput (in GWh):
Residential33,830 33,676 30,650 — %10 %
Total103,862 100,062 96,898 4 %3 %
Weather (percentage of 10-year average for service area):
Cooling degree days114 %110 %109 %4 %1 %
Heating degree days92 %120 %80 %(28)%40 %
Number of metered customers at end of period:
Residential2,455,309 2,402,329 2,359,168 2 %2 %
Total2,763,535 2,706,598 2,660,938 2 %2 %
2016 Compared to 2015. Our Energy Services business segment reported operating income of $20 million for 2016 compared to $42 million for 2015. The decrease in operating income of $22 million was due to a $25 million decrease from mark-to-market accounting for derivatives associated with certain natural gas purchases and sales used to lock in economic margins. Partially offsetting this decrease was an increase in operating income for 2016 as compared to 2015 attributable to increased throughput and number of customers due to the Continuum acquisition. Operating income in 2016 also included $3 million of operation and maintenance expenses and $3 million of amortization expenses specifically related to the acquisition and integration of Continuum. 

56
Midstream Investments


The following table summarizesprovides variance explanations by major income statement caption for Houston Electric:
Favorable (Unfavorable)
2023 to 20222022 to 2021
(in millions)
Revenues
Customer rates and impact of the change in rate design$187 $30 
Transmission Revenues, including TCOS and TCRF and impact of the change in rate design, inclusive of costs billed by transmission providers120 157 
Customer growth25 27 
Energy efficiency, partially offset in operation and maintenance below1 (3)
Refund of protected and unprotected EDIT, offset in income tax expense— 32 
Impacts from increased peak demand in the prior year, collected in rates in the current year— 2 
Miscellaneous revenues(4)5 
Equity return, related to the annual true-up of transition charges for amounts over or under collected in prior periods(5)1 
Weather impacts and other usage(15)60 
Bond Companies, offset in other line items below(44)(33)
Total$265 $278 
Operation and maintenance, excluding Bond Companies
Transmission costs billed by transmission providers, offset in revenues above$(26)$(77)
Contract services(23)3 
Energy efficiency program costs, offset in revenues above(8)3 
Support services(6)24 
Labor and benefits3 12 
All other operation and maintenance expense, including materials and supplies and insurance38 (21)
Total$(22)$(56)
Depreciation and amortization, excluding Bond Companies
Ongoing additions to plant-in-service$(114)$(50)
Total$(114)$(50)
Taxes other than income taxes
Franchise fees and other taxes$(2)$4 
Incremental capital projects placed in service, and the impact of changes to tax rates1 (14)
Total$(1)$(10)
Bond Companies expense
Operations and maintenance and depreciation expense, offset by revenues above$35 $25 
Total$35 $25 
Interest expense and other finance charges
Changes in outstanding debt$(64)$(32)
Other, primarily AFUDC and impacts of regulatory deferrals7 13 
Total$(57)$(19)
Interest expense on Securitization Bonds
Lower outstanding principal balance, offset by revenues above$5 $8 
Total$5 $8 
Other income, net
Other income, including AFUDC - equity$11 $2 
Bond Companies4 — 
Total$15 $2 

Income Tax Expense. For a discussion of effective tax rate per period, see Note 14 to the equity earnings (losses)consolidated financial statements.

57

CERC CONSOLIDATED RESULTS OF OPERATIONS

CERC’s CODM views net income as the measure of our Midstream Investments business segmentprofit or loss for 2017, 2016its reportable segment. CERC consists of a 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 2015: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 information regarding factors that may affect the future results of CERC’s consolidated operations, please read “Risk Factors” in Item 1A of Part I of this report.

 Year Ended December 31,Favorable (Unfavorable)
 2023202220212023 to 20222022 to 2021
(in millions, except throughput, weather and customer data)
Revenues:4,149 4,800 4,200 (651)600 
Expenses:
Utility natural gas1,856 2,607 1,885 751 (722)
Non-utility cost of revenues, including natural gas3 4 17 1 13 
Operation and maintenance904 886 973 (18)87 
Depreciation and amortization493 448 483 (45)35 
Taxes other than income taxes243 257 249 14 (8)
Total expenses3,499 4,202 3,607 703 (595)
Operating Income650 598 593 52 5 
Other Income (Expense)
Gain on sale— 557 11 (557)546 
Interest expense and other finance charges(178)(130)(134)(48)4 
Other income (expense), net14 (64)(4)78 (60)
Income Before Income Taxes486 961 466 (475)495 
Income tax expense (benefit)(26)236 76 262 (160)
Net Income$512 $725 $390 $(213)$335 
Throughput (in BCF):
Residential194 233 235 (17)%(1)%
Commercial and industrial386 389 396 (1)%(2)%
Total Throughput580 622 631 (7)%(1)%
Weather (percentage of 10-year average for service area):
Heating degree days86 %106 %91 %(20)%15 %
Number of customers at end of period:  
Residential3,905,388 3,859,726 4,268,385 1 %(10)%
Commercial and industrial293,235 291,184 336,828 1 %(14)%
Total4,198,623 4,150,910 4,605,213 1 %(10)%






58

 Year Ended December 31,
 2017 2016 
     2015 (1)
 (in millions)
Enable$265
 $208
 $(1,633)

(1)These amounts include impairment charges totaling $1,846 million composed of the impairment of our investment in Enable of $1,225 million and our share, $621 million, of impairment charges Enable recorded for goodwill and long-lived assets for the year ended December 31, 2015. This impairment is offset by $213 million of earnings for the year ended December 31, 2015.
Other Operations

The following table provides summary datavariance explanations by major income statement caption for our Other Operations business segment for 2017, 2016 and 2015:CERC:
Favorable (Unfavorable)
2023 to 20222022 to 2021
(in millions)
Revenues
Cost of natural gas, offset in utility natural gas, fuel and purchased power below$(728)$921 
Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale(38)(457)
Gross receipts tax, offset in taxes other than income taxes(15)19 
Weather and usage(7)22 
Refund of protected and unprotected EDIT, offset in income tax expense3 6 
Energy efficiency and other pass-through, offset in operation and maintenance8 8 
Non-volumetric and miscellaneous revenue13 26 
Non-utility revenues, including impacts of MES disposal18 (17)
Customer growth20 16 
Customer rates and impact of the change in rate design, exclusive of the TCJA impact75 56 
Total$(651)$600 
Utility natural gas
Cost of natural gas, offset in revenues above$728 $(921)
Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale23 199 
Total$751 $(722)
Non-utility costs of revenues, including natural gas
Other, primarily non-utility cost of revenues$1 $13 
Total$1 $13 
Operation and maintenance
Miscellaneous operations and maintenance expenses, including bad debt expense$(36)$(20)
Energy efficiency and other pass-through, offset in revenues above(8)(8)
Contract services— (8)
Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale3 125 
Labor and benefits11 (4)
Corporate Support Services12 2 
Total$(18)$87 
Depreciation and amortizationNine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale
Incremental capital projects placed in service$(47)$(44)
Indiana lower depreciation rates from recent rate order— 13 
Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale2 66 
Total$(45)$35 
Taxes other than income taxes
Gross receipts tax, offset in revenues$15 $(19)
Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale1 23 
Incremental capital projects placed in service(2)(12)
Total14 (8)
Gain on sale
Net gain on sale of Arkansas and Oklahoma Natural Gas businesses$(557)$546 
Total$(557)$546 
Interest expense and other finance charges
Changes in outstanding debt$(56)$(11)
Other, primarily AFUDC and impacts of regulatory deferrals8 15 
Total$(48)$4 
Other income (expense), net
Changes to non-service benefit cost, primarily settlement cost incurred in 2022$60 $(65)
Increase in Equity AFUDC9 2 
Other miscellaneous non-operating income (expenses)9 — 
Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale— 3 
Total$78 $(60)

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 Year Ended December 31,
 2017 2016 2015
 (in millions)
Revenues$14
 $15
 $14
Expenses5
 7
 3
Operating Income$9
 $8
 $11
Income Tax Expense (Benefit). For a discussion of effective tax rate per period, see Note 14 to the consolidated financial statements.


2017 ComparedSubsequent Events. On February 19, 2024, CenterPoint Energy, through its subsidiary CERC Corp., entered into the LAMS Asset Purchase Agreement to 2016. Our Other Operations business segment reported operating incomesell its Louisiana and Mississippi natural gas local distribution company businesses. The transaction is expected to close in the first quarter of $9 million for 2017 compared2025. For further information, see Note 21 to $8 million for 2016. The increase in operating income of $1 million is primarily related to decreased depreciation and amortization, partially offset by increased operating expenses.the consolidated financial statements.

2016 Compared to 2015. Our Other Operations business segment reported operating income of $8 million for 2016 compared to $11 million for 2015. The decrease in operating income of $3 million is primarily related to increased depreciation and amortization.



LIQUIDITY AND CAPITAL RESOURCES


Historical Cash Flows


The net cash provided by (used in) operating, investing and financing activities for 2017, 20162023, 2022 and 20152021 is as follows:
Year Ended December 31,
202320222021
CenterPoint EnergyHouston ElectricCERCCenterPoint EnergyHouston ElectricCERCCenterPoint EnergyHouston ElectricCERC
(in millions)
Cash provided by (used in):
Operating activities$3,877 $1,401 $2,312 $1,810 $966 $856 $22 $770 $(1,219)
Investing activities(4,233)(2,503)(1,643)(1,628)(2,435)406 (1,851)(1,617)(1,287)
Financing activities374 1,103 (668)(345)1,324 (1,277)1,916 926 2,515 
 Year Ended December 31,
 2017 2016 2015
 (in millions)
Cash provided by (used in):     
Operating activities$1,421
 $1,931
 $1,870
Investing activities(1,257) (1,046) (1,387)
Financing activities(245) (808) (517)


Cash Provided by Operating Activities

NetActivities. The following items contributed to increased (decreased) net cash provided by operating activities decreased $510 millionactivities:
Year Ended December 31,
2023 compared to 20222022 compared to 2021
CenterPoint EnergyHouston
 Electric		CERCCenterPoint EnergyHouston
 Electric		CERC
(in millions)
Changes in net income after adjusting for non-cash items$394 $235 $170 $(492)$211 $(169)
Changes in working capital917 229 358 (615)(177)(107)
Changes in net regulatory assets and liabilities (1)
809 (89)908 2,529 196 2,339 
Changes in equity in earnings of unconsolidated affiliates (2)
— — — 339 — — 
Changes in distributions from unconsolidated affiliates (2)
— — — (155)— — 
Lower pension contribution3 — — 26 — — 
Other(56)60 20 156 (34)12 
$2,067 $435 $1,456 $1,788 $196 $2,075 

(1)The change in2017 compared to 2016 primarily due to decreased cash from working capital ($549 million) and other non-current items ($6 million), partially offset by higher net income after adjusting for non-cash and non-operating items ($45 million). The changes in working capital items in 2017 primarily related to decreased cash provided by margin deposits, net; non-trading derivatives, net; taxes receivable; net accounts receivable/payable; net regulatory assets and liabilities; inventory;liabilities at CenterPoint Energy and fuel cost under recovery; partially offset by net current assets and liabilities; and other assets and liabilities.

Net cash provided by operating activities increased $61 million in 2016 compared to 2015CERC is primarily due to highersecuritization of the incurred natural gas costs associated with the February 2021 Winter Storm Event. See Note 7 to the consolidated financial statements for more information on the February 2021 Winter Storm Event.
(2)In September 2021, CenterPoint Energy’s equity investment in Enable met the held for sale criteria and is reflected as discontinued operations on CenterPoint Energy’s Statements of Consolidated Income. For further information, see Note 4 to the consolidated financial statements.
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Investing Activities.The following items contributed to (increased) decreased net income after adjusting for non-cash and non-operating items ($40 million) and increased cash from other non-current items ($32 million), partially offset by changes in working capital ($11 million). The changes in working capital items in 2016 primarily related to decreased cash provided by net regulatory assets and liabilities; fuel cost under recovery; and net accounts receivable/payable; partially offset by increased cash provided by taxes receivable; margin deposits, net; non-trading derivatives, net; and net current assets and liabilities.

Cash Used in Investing Activities

Net cash used in investing activities increased $211 million in 2017 comparedactivities:
Year Ended December 31,
2023 compared to 20222022 compared to 2021
CenterPoint EnergyHouston
 Electric		CERCCenterPoint EnergyHouston
 Electric		CERC
(in millions)
Proceeds from the sale of equity securities$(702)$— $— $(618)$— $— 
Net change in capital expenditures18 157 42 (1,255)(817)(337)
Transaction costs related to the Enable Merger— — — 49 — — 
Cash received related to Enable Merger— — — (5)— — 
Net change in notes receivable from unconsolidated affiliates— (238)(1)— — — 
Proceeds from divestitures(1,931)— (2,075)2,053 — 2,053 
Other10 13 (15)(1)(1)(23)
$(2,605)$(68)$(2,049)$223 $(818)$1,693 

Financing Activities.The following items contributed to 2016 primarily due to(increased) decreased cash received for the repayment of notes receivable from Enable ($363 million), decreased proceeds from the sale of marketable securities associated with the Charter merger ($178 million), increased cash used for acquisitions ($30 million) and increased capital expenditures ($12 million), which were partially offset by decreased cash used for the purchase of Series A Preferred Units ($363 million) and increased restricted cash ($10 million). In 2017, we acquired AEM for $132 million in cash and, in 2016, we acquired Continuum for $102 million in cash.

Net cash used in investing activities decreased $341 million in 2016 compared to 2015 primarily due to increased cash received for the repayment of notes receivable from Enable ($363 million), increased return of capital from Enable ($149 million), proceeds from the sale of marketable securities associated with the Charter merger ($146 million) and decreased capital expenditures ($170 million), which were partially offset by cash used for the purchase of Series A Preferred Units ($363 million), cash used for the Continuum acquisition ($102 million) and increased restricted cash ($17 million).

Cash Used in Financing Activities

Netnet cash used in financing activities decreased $563 million in 2017 compared to 2016 primarily due to increased proceeds from issuances of long-term debt ($496 million), decreased distributions to ZENS holders ($178 million), decreased losses on reacquired debt ($17 million), increased short-term borrowings ($9 million) and decreased payments of long-term debt ($7 million), partially offset by decreased proceeds from commercial paper ($120 million), increased payments of common stock dividends ($18 million) and increased debt issuance costs ($4 million).activities:

Year Ended December 31,
2023 compared to 20222022 compared to 2021
CenterPoint EnergyHouston
 Electric		CERCCenterPoint EnergyHouston
 Electric		CERC
(in millions)
Net changes in commercial paper outstanding$(981)$— $(227)$(1,206)$— $(646)
Net changes in long-term debt outstanding, excluding commercial paper2,560 373 (778)(1,231)386 (936)
Net changes in debt and equity issuance costs(19)4 — 2 (5)(4)
Net changes in short-term borrowings(462)— (462)479 — 479 
Redemption of Series A Preferred Stock(800)— — — — — 
Increased payment of Common Stock dividends(45)— — (55)— — 
Decreased (increased) payment of Preferred Stock dividends(1)— — 58 — — 
Payment of obligation for finance lease485 485 — (306)(306)— 
Net change in notes payable from affiliated companies— (772)1,517 — (374)(2,007)
Contribution from parent— (258)211 — 1,013 149 
Dividend to parent— (51)348 — (316)(827)
Other(18)(2)— (2)— — 
$719 $(221)$609 $(2,261)$398 $(3,792)
Net cash used in financing activities increased $291 million in 2016 compared to 2015 primarily due to increased payments of long-term debt ($574 million), increased distributions to ZENS holders ($146 million), loss on reacquired debt ($22 million), increased payments of common stock dividends ($17 million) and debt issuance costs ($9 million), which were partially offset by increased proceeds from long-term debt ($400 million), increased proceeds from commercial paper ($66 million) and increased short-term borrowings ($8 million).



Future Sources and Uses of Cash


OurThe Registrants expect that anticipated 2024 cash needs will be met with borrowings under their credit facilities, proceeds from the issuance of long-term debt, proceeds from sales of Common Stock under the Equity Distribution Agreement further described in Note 21 to the consolidated financial statements, anticipated cash flows from operations, and with respect to CenterPoint Energy and CERC, proceeds from commercial paper. Discretionary financing or refinancing may result in the issuance of equity securities of CenterPoint Energy or debt securities of the Registrants in the capital markets or the arrangement of additional credit facilities or term bank loans. Issuances of equity or debt in the capital markets, funds raised in the commercial paper markets and additional credit facilities may not, however, be available on acceptable terms.

Material Current and Long-term Cash Requirements. The liquidity and capital requirements of the Registrants are affected primarily by our results of operations, capital expenditures, debt service requirements, tax payments, working capital needs and various regulatory actions. Our principal anticipated cash requirements for 2018 include the following:

capital expenditures of approximately $1.7 billion;

scheduled principal payments on Securitization Bonds of $434 million;

contributions of a minimum of $60 million to our qualified pension plan;

maturing collateralized pollution control bonds of $50 million; and

dividend payments on our common stock and interest payments on debt.

We expect that anticipated 2018 cash needs will be met with borrowings under our credit facilities, proceeds from commercial paper, proceeds from the issuance of long-term debt, anticipated cash flows from operations and distributions from Enable. In addition, should we choose to sell Enable common units in 2018 (reducing the amount of future distributions we receive from Enable), any net proceeds we receive from such sale could provide a source for our 2018 cash needs. Discretionary financing or refinancing may result in the issuance of equity or debt securities in the capital markets or the arrangement of additional credit facilities. Issuances of equity or debt in the capital markets, funds raised in the commercial paper markets, additional credit facilities and any sales of our Enable common units may not, however, be available to us on acceptable terms.

The following table sets forth our actual capital expenditures for 2017 and estimates of our capital expenditures for currently planned projects for 2018 through 2022: 
 2017 2018 2019 2020 2021 2022
 (in millions)
Electric Transmission & Distribution$924
 $949
 $958
 $1,004
 $959
 $900
Natural Gas Distribution523
 635
 612
 637
 664
 687
Energy Services11
 20
 15
 15
 15
 15
Other Operations36
 60
 38
 33
 32
 32
Total                                                             $1,494
 $1,664
 $1,623
 $1,689
 $1,670
 $1,634

Our capitalCapital expenditures are expected to be used for investment in infrastructure for our electric transmission and distribution operations and our natural gas distribution operations. These capital expenditures are anticipated to maintain reliability and safety, increase resiliency and
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expand our systems through value-added projects. In addition to dividend payments on CenterPoint Energy’s Common Stock and interest payments on debt, the Registrants’ principal anticipated cash requirements for 2024 include the following:

CenterPoint EnergyHouston ElectricCERC
(in millions)
Estimated capital expenditures$3,669 $1,895 $1,385 
Maturing CenterPoint Energy senior notes850 — — 
Scheduled principal payments on Securitization Bonds178 161 — 
Maturing SIGECO first mortgage bonds22 — — 
Minimum contributions to pension plans and other post-retirement plans17 1 4 

The following table sets forth the Registrants’ estimates of our contractualthe Registrants’ capital expenditures currently planned for projects for 2024 through 2028. See Note 17 to the consolidated financial statements for CenterPoint Energy’s actual capital expenditures by reportable segment for 2023. 
 20242025202620272028
CenterPoint Energy(in millions)
Electric$2,205 $3,341 $3,589 $3,080 $3,018 
Natural Gas1,450 1,432 1,604 1,469 1,344 
Corporate and Other14 20 20 20 20 
Total                                                             $3,669 $4,793 $5,213 $4,569 $4,382 
Houston Electric (1)
$1,895 $2,598 $2,663 $2,822 $2,816 
CERC (1)
$1,385 $1,370 $1,486 $1,391 $1,271 

(1)Houston Electric and CERC each consist of a single reportable segment.

Capital Expenditures for Climate-Related Projects. As part of its approximately $44.5 billion 10-year capital expenditure plan, which concludes in 2030, 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.

The following table summarizes the Registrants’ material current and long-term cash requirements as of December 31, 2023.
Total20242025-20262027-20282029 and thereafter
(in millions)
CenterPoint Energy
Securitization Bonds (1)
$502 $178 $27 $29 $268 
Other long-term debt (1) (2)
18,282 872 2,311 3,894 11,205 
Interest payments — Securitization Bonds (3)
187 27 32 29 99 
Interest payments — other long-term debt (3)
9,238 835 1,652 1,317 5,434 
Short-term borrowings4 4 — — — 
Commodity and other commitments (4)
6,749 993 2,002 982 2,772 
Total cash requirements$34,962 $2,909 $6,024 $6,251 $19,778 
Houston Electric
Securitization Bonds (1)
$161 161 — — — 
Other long-term debt (1)
7,513 — 300 800 6,413 
Interest payments — Securitization Bonds (3)
4 4 — — — 
Interest payments — other long-term debt (3)
5,340 306 610 583 3,841 
Total cash requirements$13,018 $471 $910 $1,383 $10,254 
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Total20242025-20262027-20282029 and thereafter
(in millions)
CERC
Long-term debt$4,700 $— $70 $1,740 $2,890 
Interest payments — long-term debt (3)
2,213 240 478 398 1,097 
Short-term borrowings4 4 — — — 
Commodity and other commitments (4)
4,245 679 1,083 799 1,684 
Total cash requirements$11,162 $923 $1,631 $2,937 $5,671 

(1)Balances reflect aggregate principal amounts outstanding and do not include unamortized discounts, premiums or issuance costs. See Note 13 to the consolidated financial statements for additional information.
(2)ZENS obligations includingare included in the 2029 and thereafter column at their contingent principal amount of $18 million as of December 31, 2023. These obligations are exchangeable for cash at any time at the option of the holders for 95% of the current value of the reference shares attributable to each ZENS ($538 million as of December 31, 2023), as discussed in Note 11 to the consolidated financial statements.  
(3)The Registrants calculated estimated interest payments due by period:for long-term debt as follows: for fixed-rate debt and term debt, the Registrants calculated interest based on the applicable rates and payment dates; for variable-rate debt and/or non-term debt, the Registrants used interest rates in place as of December 31, 2023. The Registrants typically expect to settle such interest payments with cash flows from operations and short-term borrowings.
(4)For a discussion of commodity and other commitments, see Note 15(a) to the consolidated financial statements.
Contractual Obligations Total 2018 2019-2020 2021-2022 2023 and thereafter
  (in millions)
Securitization Bonds $1,868
 $434
 $689
 $430
 $315
Other long-term debt (1)
 7,316
 50
 —
 3,549
 3,717
Interest payments — Securitization Bonds (2)
 191
 65
 76
 38
 12
Interest payments — other long-term debt (2)
 3,756
 277
 548
 459
 2,472
Short-term borrowings 39
 39
 —
 —
 —
Operating leases (3)
 26
 5
 9
 7
 5
Benefit obligations (4)
 —
 —
 —
 —
 —
Non-trading derivative liabilities 24
 20
 4
 —
 —
Commodity and other commitments (5)
 1,286
 500
 550
 128
 108
Total contractual cash obligations (6)
 $14,506
 $1,390
 $1,876
 $4,611
 $6,629


The table above does not include the following:



(1)
ZENS obligations are included in the 2023 and thereafter column at their contingent principal amount as of December 31, 2017 of $505 million.  These obligations are exchangeable for cash at any time at the option of the holders for 95% of the current value of the reference shares attributable to each ZENS ($960 million as of December 31, 2017), as discussed in Note 11 to our consolidated financial statements.  

(2)
We calculated estimated interest payments for long-term debt as follows: for fixed-rate debt and term debt, we calculated interest based on the applicable rates and payment dates; for variable-rate debt and/or non-term debt, we used interest rates in place as of December 31, 2017. We typically expect to settle such interest payments with cash flows from operations and short-term borrowings.

(3)For a discussion of operating leases, please read Note 15(c) to our consolidated financial statements.

(4)
In 2018, we expect to contribute a minimum of approximately $60 million to our qualified pension plan. We expect to contribute approximately $7 million and $16 million, respectively, to our non-qualified pension and postretirement benefits plans in 2018.

(5)For a discussion of commodity and other commitments, please read Note 15(a) to our consolidated financial statements.

(6)This table does not include estimated future payments for expected future AROs. These payments are primarily estimated to be incurred after 2022. We record a separate liability for the fair value of AROs, which totaled $281 million as of December 31, 2017. See Note 3(c) to our consolidated financial statements.

•estimated future payments for expected future AROs primarily estimated to be incurred after 2026. See Note 3(c) to the consolidated financial statements for further information.
•expected contributions to pension plans and other postretirement plans in 2024. See Note 8(g) to the consolidated financial statements for further information.
•operating leases. See Note 20 to the consolidated financial statements for further information.

Off-Balance Sheet Arrangements

Arrangements.Other than operatingHouston Electric’s general mortgage bonds issued as collateral for tax-exempt long-term debt of CenterPoint Energy (see Note 13 to the consolidated financial statements) and short-term leases, wethe Registrants have no off-balance sheet arrangements.


Regulatory Matters


Brazos Valley Connection ProjectFebruary 2021 Winter Storm Event


Construction beganFor information about the February 2021 Winter Storm Event, see Note 7 to the consolidated financial statements.

Indiana Electric Securitization of Generation Retirements (CenterPoint Energy)

For further information about the issuance of SIGECO Securitization Bonds, see Note 7 to the consolidated 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,
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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 Ind. Code Ch. 8-1-8.8, approved the proposed levelized rate and associated ratemaking and accounting treatment. Due to inflationary pressures, the developer disclosed that costs have exceeded the agreed upon levels in the BTA. Once pricing is updated and parties determine whether to continue with the project, Indiana Electric may have to refile for approval of the project with the IURC, which could delay the in-service date from 2025 to 2026. If Indiana Electric is not able to reach a mutually acceptable solution with the developers of the Pike County Solar project, Indiana Electric may seek to terminate 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 generation. The wind project is located in MISO’s Central Region. Indiana Electric has approval 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, and thereby authorizing Indiana Electric to purchase the wind generating facility. However, as of the date of this Form 10-K, 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 could be delayed from 2025 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 could be delayed from 2024 to 2025. 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 could be delayed from 2025 to 2026.

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
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estimated $334 million turbine facility is being constructed at the previous site of the A.B. Brown power plant in Posey County, Indiana and will 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 Brazos Valley Connectionfacility. 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 2017,20, 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.

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

Culley Unit 3 Operations

In June 2022, F.B. Culley Unit 3, an Indiana Electric coal-fired electric generation unit with an installed generating capacity of 270 MW, experienced an operating issue relating to its boiler feed pump turbine. 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 recommended disallowances between $21 million to $27 million. On October 23, 2023, Indiana Electric filed rebuttal testimony with the IURC and an evidentiary hearing was held on November 2, 2023. Indiana Electric expects a decision from the IURC in the first half of 2024.

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

On December 17, 2020, Houston Electric expectsfiled a CPCN 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, constructionwhich is anticipated to occur in the first quarter of 20182025.

Kilgore Transmission Project (CenterPoint Energy and energize the Brazos Valley Connection in the early second quarter of 2018, ahead of the original June 1, 2018 energization date.Houston Electric)

On August 30, 2023, Houston Electric anticipatesfiled 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 finalexisting 138 kV Chevron to Langston circuit number 86 on Houston Electric’s transmission system to Houston Electric’s planned Kilgore substation. 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 and have been estimated to be approximately $285$60 million which is withinto $99 million. A decision on the estimated rangeapproval of approximately $270-$310 million in the PUCT’s original order.

Bailey-Jones Creek Project

In April 2017, Houston Electric submitted a proposal to ERCOT requesting its endorsement of Houston Electric’s approximately $250 million transmission project in the greater Freeport,PUCT proceeding is expected in the first quarter of 2024.

Mill CreekTransmission 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 area, which includes enhancementsthat will connect Houston Electric’s transmission system to two existing substationsHouston Electric’s planned Mill Creek substation. 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 and have been estimated to be $61 million to $90 million. A decision on the approval of the project in the PUCT proceeding is expected in the second or third quarter of 2024.

Texas Legislation (CenterPoint Energy, Houston Electric and CERC)

Houston Electric and CERC are 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:

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•House Bill 1500 is effective September 1, 2023 and continues the functions of the PUCT, the Office of Public Utility Counsel, and ERCOT through 2029. This bill also includes an amendment that clarifies the use cases under which TDUs may lease and operate temporary generation during “significant” power outages;
•House Bill 2263 is effective June 12, 2023 and authorizes local distribution companies to offer programs to promote energy conservation and to recover costs prudently incurred to implement such programs under Railroad Commission authority;
•House Bill 2555 is effective June 13, 2023 and allows an electric utility to create a new 345 kV double-circuit transmission line.and distribution system resiliency plan with the PUCT and associated cost recovery to enhance its system through hardening, undergrounding certain lines, flood mitigation measures, and vegetation management. On January 18, 2024 the PUCT issued an Order adopting its Resiliency Plan Rule (16 TAC 25.62);
•Senate Bill 947 is effective September 1, 2023 and creates severe criminal offenses for intentional damage to critical infrastructure facilities that create extended power outages;
•Senate Bill 1015 is effective June 18, 2023 and allows utilities to file the DCRF twice a year, on any day the PUCT is open (at least 185 days after filing a full base rate proceeding) and setting an administrative approval timeline of 60 days;
•Senate Bill 1016 is effective May 5, 2023 and requires the PUCT to presume that all employee compensation and benefits are reasonable and necessary when establishing a utility’s rates if based upon market compensation studies issued within the last three years; it includes exceptions for utility officer incentives that are based on financial metrics. Certain incentive compensation that is in-line with market studies will be presumed reasonable and recoverable; and
•Senate Bill 1076 is effective June 2, 2023 and moves the timeline for the PUCT to approve 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 greenhouse gas emissions using technologies such as carbon capture).

On June 28, 2023, CERC submitted its first innovation plan to the MPUC; the five-year plan includes 18 pilot projects and seven smaller research-and-development projects. These projects will deploy and evaluate a broad array of innovative resources including made-in-Minnesota alternative gases such as renewable natural gas and green hydrogen as well as pioneering technologies such as a networked geothermal district energy system and end-use carbon capture. The proposed plan requires approval from the MPUC through a review process that is expected to take about one year. The MPUC 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, reply comments are due March 15, 2024 and supplemental comments are due May 15, 2024; CERC anticipates the MPUC will hear this matter after the final comments are received.

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 a DOC investigation on anti-dumping and countervailing duties petition filed by a domestic solar manufacturer, (ii) the December 2021 Uyghur Forced Labor Prevention Act on solar modules and other products manufactured in China's Xinjiang Uyghur Autonomous Region and (iii) persistent general global supply chain and labor availability issues. On December 12, 2017, Houston Electric received approval from ERCOT, and anticipates that2, 2022, the PUCT will provide a decision in 2019 regarding the design and routeDOC issued its preliminary determination, finding four of the project.eight companies being investigated are attempting to bypass U.S. duties. On August 18, 2023, the DOC announced its final determination and found that five of the eight companies investigated are attempting to bypass U.S. duties by doing minor

66

processing in one of the Southeast Asian countries before shipment to the United States. Pursuant to President Biden’s executive order issued in June 2022, duties will not be collected on any solar module and cell imports from these Southeast Asian countries until June 2024, as long as the imports are consumed in the U.S. market within six months of the termination of the executive order. The executive order could be subject to legal challenges and its effects remain uncertain. The resolution of these issues will determine what additional costs or delays our solar projects will be subject to. These impacts have resulted in cost increases for certain projects, and may result in cost increases in other projects, and such impacts have resulted in, or are expected to result in, the need for us to seek additional regulatory review and approvals. Additionally, significant changes to project costs and schedules as a result of these factors could impact the viability of the projects. For more information regarding potential delays, cancellations and supply chain disruptions, see “Item 1A. Risk Factors— Risk Factors Affecting Operations — Electric Generation, Transmission and Distribution — Increases in the cost or...” in this report.

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 pursuant to Ind. Code ch. 8-1-39 (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.

Rate Change Applications


Houston Electric and CERCThe Registrants are routinely involved in rate change applications before state regulatory authorities. Those applications include general rate cases, where the entire cost of service of the utility is assessed and reset. In addition, Houston Electric isRegistrants are periodically involved in proceedings to adjust its capital tracking mechanisms (TCOS(e.g., CSIA, DCRF, DRR, GRIP, TCOS, ECA, CECA and DCRF) and annually files to adjust its EECRF.  CERC is periodically involved in proceedings to adjust its capital tracking mechanisms in Texas (GRIP)TDSIC), its cost of service adjustments in Arkansas, Louisiana, Mississippi(e.g., RSP and Oklahoma (FRP, RSP, RRA and PBRC)RRA), its decoupling mechanism in Minnesota,(e.g., Decoupling and SRC), and its energy efficiency cost trackers (e.g., CIP, DSMA, EECR, EECRF, EEFC and EEFR).

Houston Electric Rate Case.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 Arkansas, Docket No. 49421. Therefore, Houston Electric is required to file its next base rate proceeding no later than March 9, 2024.

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 requested increase is approximately 3.1% or $37 million based on an historical test year ending June 30, 2023. 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 10.50% ROE on a 60.61% equity ratio. Intervenor testimony is due in early March 2024, followed by staff testimony. Rebuttal testimony is due in late March 2024 and a hearing on the merits is scheduled for mid-April 2024. A final order is expected in Q2 2024.

Minnesota MississippiRate Case. On November 1, 2023, CERC filed an application with the MPUC requesting an adjustment to delivery charges in 2024 and Oklahoma (EECR, CIP, EECR2025 for the natural gas business in Minnesota. The requested increase is approximately 6.5% or $85 million for 2024 and EECR). 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 of $69 million were implemented as of January 1, 2024. A decision on 2025 interim rates was delayed until the fourth quarter of 2024. 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 ensure the safety and reliability of the system and normal increases in operating expenses. The rate case
67

reflects a proposed 10.4% ROE on a 55% equity ratio. A hearing is scheduled for late-April through mid-May 2024. A final order is expected in the fourth quarter of 2024.

The table below reflects significant applications pending or completed during 2017 and to date in 2018.






since the Registrants’ combined 2022 Form 10-K was filed with the SEC through February 20, 2024.
Mechanism
Mechanism
Annual Increase (Decrease) (1)
(in millions)
Filing
 Date
Filing
 Date
Effective DateApproval DateAdditional Information
CenterPoint Energy and Houston Electric (PUCT)
AMSN/A
June
2017DCRF (1)
86September 2017December 20172023TBDFinal reconciliation of AMS surcharge for a $29.2 million refund of AMS revenue in excess of expenses, for which a reserve has been recorded. Refunds began in September 2017 and will continue through August 2018.
EECRF (2)TBD$11.0
June
2017
March 2018November 2017Annual reconciliation filing for program year 2016 and includes performance bonus of $11 million.
DCRF41.8
April
 2017
September
2017
July
2017
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 a revenue increase of $86 million, adjusted for load growth. This is the second DCRF filing made in 2023; filing two DCRFs in a year was authorized in 2023 legislative session. A request for interim rates to be implemented on February 12, 2024 was also made on December 14, 2023; the interim rate request was denied on January 9, 2024. On December 28, 2023, an increaseintervenor requested a good cause extension, on January 5, 2024, certain parties supported it, and it was granted on January 9, 2024. On January 24, 2024, certain intervenors requested an evidentiary hearing, and the request was denied on January 25, 2024. On February 5, 2024, Houston Electric notified the ALJ that the parties have reached an agreement in eligible distribution-invested capitalprinciple on all issues in this proceeding, and filed an agreed expedited motion for 2016interim rates. On February 6, 2024, the PUCT ALJ issued an order denying to abate the proceeding and retaining the procedural schedule already established. On February 7, 2024, Houston Electric on behalf of $479 million. Unanimous Stipulationitself and Settlement Agreementall parties responded to the February 6, 2024 order to clarify that the abatement request was filed in June 2017not intended to alter the statutory timeframe for $86.8a decision. On February 9, 2024, the PUCT ALJ issued an order setting filing deadlines and requesting briefing on interim rates. On February 13, 2024, interim rates designed to collect $220 million (a $41.8($73 million annual increase).  The settlement agreement also included the AMS refund referenced above.incremental) were approved, to be effective April 2024.
TCOS447.8August 2023October 2023December 2016October 2023
February
2017
February
2017		Based on an incremental increase in total rate base of $109.6 million.
TCOS39.3September 2017November 2017November 2017Based on an incremental increase in total rate base of $263.4 million.
TCOSN/A
February
2018
TBDTBDRevise TCOS application approved in November 2017 by a reduction of $41.6 million to recognize change in tax rates, amortize certain EDIT balances and adjust rate base by EDIT attributable to new plant since the last rate case, all of which are related to the TCJA.
South Texas and Beaumont/East Texas (Railroad Commission)
GRIP7.6
March
 2017
July
2017
June
2017
Based on net change in invested capital of $46.5 million.$405 million for the period February 1, 2023 through June 30, 2023. Notice of Approval issued October 6, 2023.
Rate CaseEECRF (1)
16June
2023		March 2024November 2023The requested $53 million is comprised primarily of the following: 2024 program costs of $38 million; a credit of $2 million related to the over-recovery of 2022 program costs; the 2022 earned bonus of $16 million; and 2024 projected evaluation, measurement and verification costs of $1 million. An order approving performance bonus and rates was issued November 3, 2023.
(DCRF
70April
2023		September 2023September 2023The net change in distribution invested capital since its last base rate proceeding of approximately $1.9 billion for the period January 1, 2019 through December 31, 2022 for a revenue increase of $85 million, adjusted for load growth. On July 14, 2023 a settlement was filed that results in a revenue increase of $70 million adjusted for load growth. Order approving the rates included in the settlement was issued September 14, 2023.
TEEEF (1)
114April
2023		December 2023February 2024A total Rider TEEEF revenue requirement of $188 million for cost incurred through December 31, 2022. The revenue change between the rates resulting from the 2022 TEEEF and this application is $149 million. Interim rates effective September 1, 2023. Settlement in principle announced and motion to abate filed October 12, 2023 and updated interim rates were effective December 15, 2023. The settlement incorporates an 8 1/2 year amortization period. The PUCT approved the settlement in its order that was issued February 1, 2024.
TCOS40March 2023May
2023		May
2023		Based on net change in invested capital of $367 million for the period August 1, 2022 through January 31, 2023.
DCRF and TEEEF117April
 2022		April
2023		April 2023Original filing included both capital that has traditionally been recovered under DCRF and TEEEF capital; the filing was separated into traditional DCRF and TEEEF in June 2022. The traditional DCRF portion revenue requirement of $78 million was approved and was implemented September 1, 2022. A final order was issued on April 5, 2023 approving a TEEEF revenue requirement of $39 million with rates effective April 15, 2023. On April 28, 2023 and May 1, 2023 certain intervenors filed motions for rehearing of the PUCT’s April 5, 2023 order. On May 25, 2023 the PUCT issued its order on rehearing which clarified some of the findings, but did not change the approval of TEEEF cost recovery. On June 19, 2023 certain intervenors filed motions for rehearing of the May 25, 2023 order on rehearing. The PUCT denied the motions for rehearing in an order issued on August 3, 2023. See Note 7 to the consolidated financial statements for further information.
CenterPoint Energy and CERC - Beaumont/East Texas, South Texas, only)0.5November 2017TBDTBDReflects a proposed 10.3% ROE on a 55% equity ratio for South Texas jurisdiction.
Houston and Texas Coast (Railroad Commission)
Rate CaseGRIP6016.5March 2023June
2023		November 2016June
2023
May
2017
May
2017
The Railroad Commission approved a unanimous settlement agreement establishing parametersBased on net change in invested capital for future GRIP filings, including a 9.6% ROE on a 55.15% equity ratio.calendar year 2022 of $390 million.
Texarkana,
Rate Case (1)
37October 2023TBDTBD
See discussion above under Texas Service Area (Multiple City Jurisdictions)Gas Rate Case.
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Mechanism
Annual Increase (Decrease) (1)
(in millions)
Filing
 Date		Effective DateApproval DateAdditional Information
Rate Case1.1
July
2017
September
2017
August 2017Approved rates are consistent with Arkansas rates approved in 2016.CenterPoint Energy and CERC - Louisiana (LPSC)
Arkansas (APSC)
EECR (2)RSP60.5September 2022May
2023
May
2017
April 2023January 2018September 2017Recovers $11.0 million, including an incentive of $0.5 million based on 2016 program performance.
FRP7.6April
2017		October
2017		September 2017Based on ROE of 9.5% as approved9.95% with 50 basis point (+/-) earnings band. The North Louisiana increase, net of TCJA effects considered outside of the earnings band, is $3 million based on a test year ended June 2022 and adjusted ROE of 7.05%. The South Louisiana increase, net of TCJA effects considered outside of the earnings band, is $5 million based on a test year ended June 2022 and adjusted ROE of 4.19%. The TCJA refund impact to North Louisiana and South Louisiana was $1 million and $1 million, respectively. North Louisiana and South Louisiana also seek to recover regulatory assets due to COVID-19 bad debt expenses in the lastamounts of $0.7 million and $0.3 million, respectively. On April 5, 2023 the LPSC issued an order approving a joint settlement for $2.7 million in North Louisiana and $4.6 million in South Louisiana in addition to the full impacts of TCJA and COVID-19 recoveries. Implementation occurred in May 2023 upon approval of compliance tariff.
RSP(1)
12September/October 2023TBDTBDBased 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.
CenterPoint Energy and CERC - Minnesota (MPUC)
CIP Financial Incentive8May 2023September 2023October 2023CIP Financial Incentive based on 2022 CIP program activity.
Rate Case (1)
136November 2023TBDTBD
See discussion above under Minnesota Rate Case.
CenterPoint Energy and CERC - Mississippi
RRA     7May
2023		October 2023October 2023Based ROE of 10.098% with 100 basis point (+/-) earnings band. Revenue increase of approximately $8 million based on 2022 test year adjusted earned ROE of 5.66%. Interim increase of approximately $1 million implemented May 31, 2023. Settled increase of approximately $7 million approved and implemented October 3, 2023. Order authorized recovery of regulatory assets due to COVID-19 in the amount of $0.3 million over the 2024 calendar year.
CenterPoint Energy - Indiana South - Gas (IURC)
CSIA3April
2023		July
2023		July
2023		Requested an increase of $33 million to rate base, which reflects approximately $3 million annual increase in current revenues. 80% of revenue requirement is included in requested rate increase and 20% is deferred until the next rate case. Unanimous Settlement AgreementThe mechanism also includes a change in (over)/under-recovery variance of $1 million annually. Also included are unrecovered deferred operations and maintenance expenses of $9 million. OUCC filed on June 2, 2023, recommending approval of the proposed CSIA rates and updated plan as filed, with non-cost recommendations. Rebuttal testimony filed June 16, 2023. A hearing was held June 28, 2023. The IURC issued an Order approving the CSIA on July 26, 2023.
CSIA3October 2023February 2024January 2024Requested an increase of $31 million to rate base, which reflects approximately $3 million annual increase in current revenues. 80% of revenue requirement is included in requested rate increase and 20% is deferred until the next rate case. The mechanism also includes a change in (over)/under-recovery variance of $1 million annually. OUCC filed on December 8, 2023, recommending disallowance of two projects for customer-side replacements. Engineering rebuttal testimony was filed December 15, 2023, stating why costs were necessary for safety and integrity of customers and system. Responded to IURC docket entry requesting additional information on January 2, 2024. A hearing was held January 3, 2024. The IURC issued an order on January 31, 2024, approving the CSIA with the exception of the two projects for customer-side replacements which are not authorized for recovery. Indiana South filed revised revenue requirement schedules removing the two project costs with its compliance filing. Revised rates were effective February 1, 2024.
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Mechanism
Annual Increase (Decrease) (1)
(in July 2017 for $7.6 million and was subsequently approved.millions)
Filing
 Date		Effective DateApproval DateAdditional Information
BDA3.9
March
2017
June
2017
June
2017
For the evaluation period between January 2016CenterPoint Energy and August 2016. Amounts are recorded during the evaluation period.CERC - Indiana North - Gas (IURC)
BDACSIA916.5April
2023		July
2023		December 2017July
2023
February
2018
January
2018
ForRequested an increase of $95 million to rate base, which reflects approximately $9 million annual increase in current revenues. 80% of revenue requirement is included in requested rate increase and 20% is deferred until the evaluation period between October 2016next rate case. The mechanism also includes a change in (over)/under-recovery variance of $5 million annually. Also included are unrecovered deferred operations and September 2017. Amounts are recorded duringmaintenance expenses of $20 million. OUCC filed on June 2, 2023, recommending approval of the evaluation period.proposed CSIA rates and updated plan as filed, with non-cost recommendations. Rebuttal testimony was filed on June 16, 2023. A hearing was held June 28, 2023. The IURC issued an Order approving the CSIA on July 26, 2023.
Minnesota (MPUC)CSIA9October 2023January 2024January 2024Requested an increase of $98 million to rate base, which reflects approximately $9 million annual increase in current revenues. 80% of revenue requirement is included in requested rate increase and 20% is deferred until the next rate case. The mechanism also includes a change in (over)/under-recovery variance of $1 million annually. OUCC filed on December 8, 2023, recommending approval as filed. Responded to IURC Docket entry requesting additional information on January 2, 2024. A hearing was held January 3, 2024. The IURC issued an Order approving the CSIA on January 31, 2024 with rates effective January 31, 2024.
Rate CaseCenterPoint Energy and CERC - Ohio (PUCO)
DRR (1)
656.5May
2023		September 2023August 20172023Requested an increase of $46 million to rate base for investments made in 2022, which reflects a $6 million annual increase in current revenues. A change in (over)/under-recovery variance of $0.3 million annually is also included in rates. PUCO staff review and recommendation filed June 29, 2023, recommending approval as proposed. VEDO statement of issues resolved in case filed July 14, 2023. PUCO issued a Finding & Order approving the DRR August 23, 2023, and revised rates effective September 1, 2023.
CenterPoint Energy - Indiana Electric (IURC)
TDSICTBD2February 2023TBDJune
2023		May
2023		ReflectsRequested an increase of $31 million to rate base, which reflects a $5 million annual increase in current revenues. 80% of the revenue requirement is included in requested rate increase and 20% is deferred until next rate case. The mechanism also includes a change in (over)/under-recovery variance and a tax reform credit for a total of ($1 million). OUCC filed on April 3, 2023, recommending approval of the proposed 10.0% ROETDSIC rates and updated plan as filed. A hearing was held on a 52.18% equity ratio. Includes a proposalMay 3, 2023. On May 30, 2023, the IURC issued an order approving the TDSIC rates and updated plan as filed with rates effective June 1, 2023.
CECA—February 2023June
2023		May
2023		Requested an increase of less than $1 million to extend decoupling beyond current expiration date of June 2018. Interim rates reflectingrate base, which reflects an annual increase of $47.8less than $1 million werein current revenues. The mechanism also includes a change in (over)/under-recovery variance of less than ($1 million). OUCC filed on March 31, 2023, recommending approval of the proposed CECA cost recovery with a reduction of approximately $0.3 million. Rebuttal testimony was filed on April 6, 2023. A hearing was held on May 3, 2023. On May 30, 2023, the IURC issued an order approving the CECA rates with a cost recovery reduction of approximately $0.3 million with rates effective October 1, 2017.June 6, 2023.
CIP (2)13.8
May
2017ECA (1)
1August 2017May
2023		February 2024August 2017February 2024Annual reconciliation filing for program year 2016Requested an increase of $51 million to rate base, which reflects a $1 million annual increase in current revenues. 80% of the revenue requirement is included in requested rate increase and 20% is deferred until next rate case. The mechanism also includes performance bonusa change in (over)/under-recovery variance of $13.8less than $1 million. A hearing was held on October 24, 2023. Indiana Electric filed a proposed order on October 31, 2023. The OUCC filed a proposed order on November 8, 2023. Indiana Electric filed a response to the OUCC proposed order on November 15, 2023. A final order was issued February 7, 2024 with rates effective February 8, 2024.
Decoupling20.4September 2017
September
2017DSMA (1)
16February 2018July
2023		January 2024ReflectsNovember 2023The requested $45 million is comprised primarily of the following: 2024 program costs of $11 million and $26 million of lost revenue, under recovery for the period July 1, 2016 through June 30, 2017 and $3.0$3 million related to the under recoveryover-recovery of 2022 program costs and $11 million under-recovery related to a prior period adjustment factor. $9.2variance adjustment; the requested $45 million is an increase of $16 million compared to the prior DSMA. A settlement between Indiana Electric and $11.2the OUCC was reached concerning the $11 million under-recovery which resolves all issues related to the DSMA for January through December 2024 including the $11 million under-recovery. The settlement provides that the IURC should approve the DSMA and that Indiana Electric will arrange for educational training on demand side management offerings. A settlement hearing was recognized in 2016 and 2017, respectively.
Mississippi (MPSC)
RRA2.3
May
2017
July
2017
July
2017
Authorized ROE of 9.59% and a capital structure of 50% debt and 50% equity.
Louisiana (LPSC)
RSP1.0September 2016December 2016
April
2017
Authorized ROE of 9.95% and a capital structure of 48% debt and 52% equity.
RSP3.0September 2017December 2017held on October 24, 2023. The IURC issued an Order approving the settlement on November 22, 2023, with rates effective January 2018Authorized ROE of 9.95% and a capital structure of 48% debt and 52% equity.
Oklahoma (OCC)
EECR (2)0.4
March
 2017
November 2017October 2017Recovers $2.6 million, including an incentive of $0.4 million based on 2016 program performance.
PBRC2.2
March
2017
November 2017October 2017Based on ROE of 10%.1, 2024.

70


Mechanism
Annual Increase (Decrease) (1)
(in millions)
Filing
 Date		Effective DateApproval DateAdditional Information
TDSIC(1)
Represents3August 2023November 2023November 2023Requested an increase of $27 million to rate base, which reflects a $3 million annual increase in current revenues. 80% of the revenue requirement is included in requested rate increase and 20% is deferred until next rate case. The mechanism also includes a change in (over)/under-recovery variance and a tax reform credit for a total of ($0.2 million). OUCC filed on October 2, 2023 recommending approval of the proposed increases whenTDSIC rates. A hearing was held on October 31, 2023. The IURC issued an Order approving the TDSIC on November 29, 2023, with rates effective date and/or approval date is not yet determined. Approved rates could differ materially from proposed rates.

November 30, 2023.
(2)
Rate Case (1)
Amounts are recorded when approved.119December 2023TBDTBD
See discussion above under Indiana Electric Rate Case.
TDSIC(1)
5February 2024TBDTBDRequested 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. The mechanism also includes a change in (over)/under-recovery variance and a tax reform credit for a total of ($1 million). OUCC is expected to file testimony on April 2, 2024 and a hearing is scheduled for April 30, 2024.
CECA (1)
—February 2024TBDTBDRequested 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.

Tax Reform

(1)Represents proposed increases (decreases) when effective date and/or approval date is not yet determined. Approved rates could differ materially from proposed rates.
For Houston Electric
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 CERC’s NGD, federalalternative 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 tax expense is included in the rates approved by state commissions and local municipalities and charged by those utilitiesof certain large corporations. Corporations are entitled to consumers. When Houston Electric and NGD have general rate cases and other periodic rate adjustments, we expect the lower corporate tax expense resulting from the TCJA (which includes determining the treatment of EDIT), along with other increases and decreases in our revenue requirements, to be incorporated into Houston Electric’s and NGD’s future rates. Nevertheless, regulators may require us to responda CAMT credit to the TCJAextent CAMT liability exceeds regular tax liability, which can be carried forward indefinitely and used in other ways, including through faster recoveriesfuture years when regular tax exceeds the CAMT. The IRA did not have a material impact on the Registrants’ 2023 financial results. It is likely that CenterPoint Energy and the Registrant Subsidiaries will owe CAMT in excess of reductionstheir regular tax liability beginning in 2024. As a result, CenterPoint Energy and the Registrant Subsidiaries expect a temporary increase in federal incomecash tax expense, accounting orderspayments due to reflect a liability to return to customers in future rate proceedings, accelerated returns to consumers of previously collected deferred federal income taxes, increased funding of infrastructure upgrades, or offsets of future rate increases. The effect on us of any potential return of tax savings resulting from the TCJA to consumers may differ depending on how each regulatory body requires us to return such savings.this provision.


Greenhouse Gas Regulation and Compliance (CenterPoint Energy)

On January 25, 2018,August 3, 2015, the PUCT issued an accounting order in Project No. 47945 directing electric utilities, including Houston Electric, to record asEPA released its CPP rule, which required a regulatory liability (1) the difference between revenues collected under existing rates and revenues that would have been collected had the existing rates been set using the recently approved federal income tax rates and (2) the balance of EDIT that now exists because of the32% reduction in federal income tax rates. On February 13, 2018, Houston Electric and other likely parties to a future rate case announced a settlement that requires Houston Electric to make (i) a TCOS filing by February 20, 2018 to reflect the change in the federal income tax rate for Houston Electric’s transmission rate base through July 31, 2017 and account for certain EDIT (and such filingcarbon emissions from 2005 levels. The final rule was timely submitted), (ii) a DCRF filing in April 2018 to reflect the change in the federal income tax rate for Houston Electric’s distribution rate base through December 31, 2017 and (iii) a full rate case filing by April 30, 2019. The settlement was presented to the PUCT during its open meeting on February 15, 2018. In response to the settlement, the PUCT did not proceed with a prior proposal to require Houston Electric to file a rate case in the summer of 2018. The PUCT also amended its prior accounting order to remove the requirement that utilities include carrying costs in the new regulatory liability. 

PHMSA Matters

On December 19, 2016, PHMSA published in the Federal Register an interim finalon 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. We will continue to evaluate the applicability of the rule to impose industry-developed recommendationsexisting and new gas-fired generating units, but would note that CenterPoint Energy does not currently have plans to operate any of its coal-fired units beyond December 2029.

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 proceeded to lead negotiations at the global climate conference in Glasgow, Scotland. On April 22, 2021, President Biden announced new goals of 50% reduction of economy-wide GHG emissions, and 100% carbon-free electricity by 2035, which formed the basis of the U.S. commitments announced in Glasgow. In September 2021, CenterPoint Energy announced its net zero emissions goals for both Scope 1 emissions and certain Scope 2 emissions by 2035 as enforceable safetywell as a goal to reduce certain Scope 3 emissions by 20% to 30% by 2035.
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Because Texas is an unregulated market, CenterPoint Energy’s Scope 2 estimates do not take into account Texas electric transmission and distribution assets in the line loss calculation and, in addition, exclude emissions related to purchased power in Indiana between 2024 and 2026 as estimated. CenterPoint Energy’s Scope 3 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 the effect of reducing the consumption of natural gas. The IRA established the Methane Emissions Reduction Program, which imposes a charge on methane emissions from certain natural gas transmission facilities, and the EPA has proposed new regulations targeting reductions in methane emissions, which if implemented will increase costs related to production, transmission and storage of natural gas. Houston Electric, in contrast to some electric utilities including Indiana Electric, does not generate electricity, other than TEEEF, and thus is not directly exposed to the risk of high capital costs and regulatory uncertainties that face electric utilities that burn fossil fuels to generate electricity. CenterPoint Energy’s net zero emissions goals are aligned with Indiana Electric’s generation transition plan and are expected to position Indiana Electric to comply with anticipated future regulatory requirements related to GHG emissions reductions. Nevertheless, Houston Electric’s and Indiana Electric’s revenues could be adversely affected to the extent any resulting regulatory action has the effect of reducing consumption of electricity by ultimate consumers within their respective service territories. Likewise, incentives to conserve energy or to use energy sources other than natural gas could result in a decrease in demand for the Registrants’ services. For example, Minnesota has enacted the Natural Gas Innovation Act that seeks to provide customers with access to renewable energy resources and innovative technologies, with the goal of reducing GHG emissions.Further, certain local government bodies have introduced or are considering requirements and/or incentives to reduce energy consumption by certain specified dates. For example, Minneapolis has adopted carbon emission reduction goals in an effort to decrease reliance on fossil 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 downhole (underground) equipment, including wells, wellbore tubing,all development projects. These initiatives could have a significant impact on CenterPoint Energy and casing, at both interstateits operations, and intrastate undergroundthis 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 storage facilities. Bothbecause of its lower emissions characteristics would be expected to benefit CenterPoint Energy and CERC and Enable own and operate underground storage facilities that are subject totheir natural gas-related businesses. At this rule’s provisions, which include procedures and practices for operations, maintenance, threat identification, monitoring, assessment, site security, emergency response and preparedness, training and recordkeeping. Although not yet finalized,time, however, we cannot quantify the interim rule went into effect on January 18, 2017, with an announced compliance deadline of January 18, 2018. PHMSA determined, however, that it will not issue enforcement citations to any operators for violations of provisionsmagnitude of the interim finalimpacts 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 that had previously been non-mandatory provisions of American Petroleum Institute Recommended Practices 1170 and 1171 until one year after PHMSA issues a final rule, which has not yet been issued. This matter remains ongoing and subject to future PHMSA determinations. CERC and Enableremain uncertain, CenterPoint Energy will continue to monitor regulatory activity regarding GHG emission standards that may affect its business. Currently, CenterPoint Energy does not purchase carbon credits. In connection with its net zero emissions goals, CenterPoint Energy is expected to purchase carbon credits in the future; however, CenterPoint Energy does not currently expect the number of credits, or cost for those credits, to be material.

Climate Change Trends and Uncertainties

As a result of increased awareness regarding climate change, coupled with adverse economic conditions, availability of alternative energy sources, including private solar, microturbines, fuel cells, energy-efficient buildings and energy storage devices, and new regulations restricting emissions, including potential regulations of methane emissions, some consumers and companies may use less energy, meet their own energy needs through alternative energy sources or avoid expansions of their facilities, including natural gas facilities, resulting in less demand for the Registrants’ services. As these technologies become a more cost-competitive option over time, whether through cost effectiveness or government incentives and subsidies, certain customers may choose to meet their own energy needs and subsequently decrease usage of the Registrants’ systems and 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’
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services may increase as a result of customer changes in response to climate change. For example, as the utilization of electric vehicles increases, demand for electricity may increase, resulting in increased usage of CenterPoint Energy’s systems and services. Any negative opinions with respect to CenterPoint Energy’s environmental practices or its ability to meet the challenges posed by climate change formed by regulators, customers, investors, legislators or other stakeholders could harm its reputation.

To address these developments, CenterPoint Energy announced its net zero emissions goals for both Scope 1 emissions and assesscertain Scope 2 emissions by 2035. Indiana Electric’s 2019/2020 IRP identified a preferred portfolio that retires 730 MW of coal-fired generation facilities and replaces these resources with a mix of generating resources composed primarily of renewables, including solar, wind, and solar with storage, supported by dispatchable natural gas combustion turbines including a pipeline to serve such natural gas generation. Indiana Electric continues to execute on its 2019/2020 IRP and has received initial approvals for 756 MWs of the potential700-1,000 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. Indiana Electric plans to convert its last remaining coal unit to natural gas by 2027 and to add a significant amount of additional renewable resources through 2033. 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...”

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


Other Matters


Credit Facilities


OurThe Registrants may draw on their respective revolving credit facilities may be drawn on by the companies from time to time to provide funds used for general corporate and limited liability company purposes, including to backstop the companies’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 ourthe Registrants’ revolving credit facilities, and the 2017 amendments, please see Note 13 to ourthe consolidated 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 December 31, 2023.


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As of February 9, 2018, we12, 2024, the Registrants had the following revolving credit facilities and utilization of such facilities:
Amount Utilized as of February 12, 2024
RegistrantSize of FacilityLoansLetters of CreditCommercial PaperWeighted Average Interest RateTermination Date
(in millions)
CenterPoint Energy$2,400 $— $— $1,272 5.51%December 6, 2027
CenterPoint Energy (1)
250 — — — —%December 6, 2027
Houston Electric300 — — — —%December 6, 2027
CERC1,050 — 1 359 5.49%December 6, 2027
Total$4,000 $— $1 $1,631 
Company 
Size of
Facility
 
Amount
Utilized as of
February 9, 2018 (1)
 Termination Date
(in millions)
CenterPoint Energy $1,700
 $877
(2) 
March 3, 2022
Houston Electric 300
 4
(3) 
March 3, 2022
CERC Corp. 900
 899
(4) 
March 3, 2022
(1)This credit facility was issued by SIGECO.

(1)Based on the consolidated debt to capitalization covenant in our revolving credit facility and the revolving credit facility of each of Houston Electric and CERC Corp., we would have been permitted to utilize the full capacity of such revolving credit facilities, which aggregated $2.9 billion as of December 31, 2017.

(2)Represents outstanding commercial paper of $871 million and outstanding letters of credit of $6 million.

(3)Represents outstanding letters of credit.
(4)Represents outstanding commercial paper of $898 million and outstanding letters of credit of $1 million.


Borrowings under each of the three revolving credit facilities are subject to customary terms and conditions. However, there is no requirement that the borrower makemakes representations prior to borrowingsborrowing 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 three revolving credit facilities, the spread to LIBORSOFR 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 threefour revolving credit facilities.


Long-term Debt Transactions


In 2017, we and CERC Corp. retired or redeemed a combined $800 million aggregate principal amount of unsecured senior notes. Additionally, we issued $500 million aggregate principal amount of unsecured senior notes, CERC Corp. issued $300 million aggregate principal amount of unsecured senior notes and Houston Electric issued $300 million aggregate principal amount of general mortgage bonds. For furtherdetailed information about our 2017the Registrants’ debt transactions in 2023, see Note 13 to ourthe consolidated financial statements.


Securities Registered with the SEC


On January 31, 2017, CenterPoint Energy, Houston Electric and CERC Corp.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 CenterPoint Energy’s shares of common stock,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 January 31, 2020.May 17, 2026. For information related to the Registrants’ debt issuances in 2023, see Note 13 to the consolidated financial statements.


Temporary Investments


As of February 9, 2018, we12, 2024, the Registrants had no temporary investments.


Money Pool


We haveThe Registrants participate in a money pool through which the holding companythey and participatingcertain 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 ourCenterPoint Energy’s revolving credit facility or the sale of ourCenterPoint 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 February 12, 2024:

Weighted Average Interest RateHouston ElectricCERC
 (in millions)
Money pool investments5.57%$60 $— 

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Impact on Liquidity of a Downgrade in Credit Ratings


The interest rate on borrowings under ourthe Registrants’ credit facilities is based on ourtheir respective credit rating. On December 4, 2017, S&P revised its rating outlooks on senior debt of CenterPoint Energy, Houston Electric and CERC Corp. to stable from positive and affirmed its ratings. On September 24, 2017, Fitch upgraded Houston Electric’s senior secured debt rating to A+ and maintained its rating outlook of stable. In addition, Fitch revised its rating outlooks on senior debt of CenterPoint Energy and CERC Corp. to positive from stable and affirmed its ratings.

As of February 9, 2018,12, 2024, Moody’s, S&P and Fitch had assigned the following credit ratings to senior debt of CenterPoint Energy and certain subsidiaries:
the Registrants:
Moody’sS&PFitch
RegistrantBorrower/InstrumentRatingOutlook (1)RatingOutlook (2)RatingOutlook (3)
CenterPoint EnergyMoody’sS&PFitch
Company/InstrumentRatingOutlook (1)RatingOutlook (2)RatingOutlook (3)
CenterPoint Energy Senior Unsecured DebtBaa2Baa1StableBBBStableBBBBBB+StableBBBPositive
CenterPoint EnergyVectren Corp. Issuer Ratingn/an/aBBB+Stablen/an/a
CenterPoint EnergySIGECO Senior Secured DebtA1StableAStablen/an/a
Houston ElectricHouston Electric Senior Secured DebtA2A1StableAStableAAStableA+Stable
CERCCERC Corp. Senior Unsecured DebtA3Baa2StableBBB+StableA-A-Stable
CERCIndiana Gas Senior Unsecured DebtStablen/an/aBBBBBB+StablePositiven/an/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 rating 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.


We(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. WeThe Registrants note that these credit ratings are included for informational purposes and are not recommendations to buy, sell or hold ourthe 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 ourthe Registrants’ credit ratings could have a material adverse impact on ourthe Registrants’ ability to obtain short- and long-term financing, the cost of such financings and the execution of ourthe Registrants’ commercial strategies.


A decline in credit ratings could increase borrowing costs under ourthe Registrants’ revolving credit facilities. If ourthe Registrants’ credit ratings or those of Houston Electric or CERC Corp. had been downgraded one notch by each of the three principal credit rating agenciesS&P and Moody’s from the ratings that existed atas of December 31, 2017,2023, the impact on the borrowing costs under the threefour revolving credit facilities would have been immaterial.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 ourthe 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 ourCenterPoint Energy’s and CERC’s Natural Gas Distribution and Energy Services businessreportable segments.

CES, a wholly-owned subsidiary of CERC Corp. operating in our Energy Services business segment, provides natural gas sales and services primarily to commercial and industrial customers and electric and natural gas utilities throughout the United States. To economically hedge its exposure to natural gas prices, CES uses derivatives with provisions standard for the industry, including those pertaining to credit thresholds. Typically, the credit threshold negotiated with each counterparty defines the amount of unsecured credit that such counterparty will extend to CES. To the extent that the credit exposure that a counterparty has to CES at a particular time does not exceed that credit threshold, CES is not obligated to provide collateral. Mark-to-market exposure in excess of the credit threshold is routinely collateralized by CES. Similarly, mark-to-market exposure offsetting and exceeding the credit threshold may cause the counterparty to provide collateral to CES. As of December 31, 2017, the amount posted by CES as collateral aggregated approximately $41 million. Should the credit ratings of CERC Corp. (as the credit support provider for CES) fall below certain levels, CES would be required to provide additional collateral up to the amount of its previously unsecured credit limit. We estimate that as of December 31, 2017, unsecured credit limits extended to CES by counterparties aggregated $348 million, and $2 million of such amount was utilized.


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 Corp. might need to provide cash or other collateral of as much as $196$256 million as of December 31, 2017.2023. The amount of collateral will depend on seasonal variations in transportation levels.




ZENS and Securities Related to ZENS (CenterPoint Energy)


If ourCenterPoint Energy’s creditworthiness were to drop such that ZENS holders thought ourits 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 TWZENS-Related Securities that we ownCenterPoint Energy owns or from other sources. We ownCenterPoint Energy owns shares of TWZENS-Related Securities equal to approximately 100% of the reference shares used to calculate ourits obligation to the holders of the ZENS. ZENS exchanges result in a cash outflow because tax deferrals related to the ZENS and TWshares of ZENS-Related Securities shares would typically cease when ZENS are exchanged or otherwise retired and TWshares of ZENS-Related Securities shares 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 December 31, 2017,2023, deferred taxes of approximately $521$728 million would have been payable in 2017, based on 2017 tax rates in effect.2023. If all the TWZENS-Related Securities had been sold on December 31, 2017,2023, capital gains taxes of approximately $297$81 million
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would have been payable in 2017.

2023 based on 2023 tax rates in effect. For additional information about ZENS, see Note 11 to ourthe consolidated financial statements.


Cross Defaults


Under oureach of CenterPoint Energy’s, Houston Electric’s and CERC’s respective revolving credit facility,facilities and CERC’s term loan agreement, a payment default on, or a non-payment default, event or condition that permits acceleration of, any indebtedness for borrowed money and certain other specified types of obligations (including guarantees) exceeding $125 million by usthe borrower or any of ourtheir respective significant subsidiaries will cause a default.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 ourits subsidiaries’ debt instruments or revolving credit facilities.


Possible Acquisitions, Divestitures and Joint Ventures


From time to time, wethe 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. WeThe 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 usthe 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.

In February 2016, we announced that we were evaluating strategic alternatives for our investment CenterPoint Energy has increased its planned capital expenditures in Enable, includingits Electric and Natural Gas businesses multiple times over the recent years to support rate base growth. The Registrants may continue to explore asset sales as a sale or spin-off qualifying under Section 355means to efficiently finance a portion of the U.S. Internal Revenue Code. We have determined that we will no longer pursue a spin option at this time. More recently, we announced that late-stage discussions with a third party regarding a transaction involving our investment in Enable had terminated because an agreement on mutually acceptable terms could not be reached. We may reduce our ownership in Enable over time through salesits increased capital expenditures in the public equity markets, or otherwise, of the common units we hold,future, subject to market conditions. Although athe conditions listed above. For further information, see Note 4.

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 local distribution company businesses. The transaction for all our interests in Enable is not viable at this time, we may pursue such a transaction if it is viableexpected to close in the future. There can be no assurances that we will engage in any specific action or that any sale transaction or any salefirst quarter of common units in2025. For further information, see Note 21 to the public equity markets or otherwise will be completed, and we do not intend to disclose further developments unless and until our Board of Directors approves a specific action or as otherwise required by applicable law or NYSE regulations. Any sale transaction or sale of common units in the public equity markets or otherwise may involve significant costs and expenses, including, in connection with any public offering, a significant underwriting discount. We may not realize any or all of the anticipated strategic, financial, operational or other benefits from any completed sale or reduction in our investment in Enable.

Enable Midstream Partners

We receive quarterly cash distributions from Enable on its common units and Series A Preferred Units we own. A reduction in the cash distributions we receive from Enable could significantly impact our liquidity. For additional information about cash distributions from Enable, see Notes 10 and 19 to our consolidated financial statements.


Hedging of Interest Expense for Future Debt Issuances


During 2016, 2017 and 2018, we enteredFrom time to time, the Registrants may enter into forward 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 8(a)9(a) to ourthe consolidated financial statements.



Weather Hedge

We have historically entered into partial weather hedges for certain NGD jurisdictions and Houston Electric’s service territory to mitigate the impact of fluctuations from normal weather. We remain exposed to some weather risk as a result of the partial hedges. For more information about our weather hedges, see Note 8(a) to our consolidated 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. AdverseBefore conducting business, a REP must register with the PUCT and must meet certain financial qualifications. Nevertheless, adverse economic conditions, 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’s default, Houston Electric’s tariff provides a number of remedies, including the option for Houston Electric to request that the PUCT suspend or revoke the certification of the REP. Applicable regulatory provisions require that customers be shifted to another REP or a provider of last resort if a REP cannot make timely payments. However, Houston Electric remains at risk for payments related to services provided prior to the shift to the replacement REP or the provider of last resort. If a REP were unable to meet its obligations, it could consider, among various options, restructuring under the bankruptcy laws, in which event such REP might seek to avoid honoring its obligations and claims might be made against Houston Electric involving payments it had received from such REP. If a REP were to file for bankruptcy, Houston Electric may not be successful in recovering accrued receivables owed by such REP that are unpaid as of the date the REP filed for 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.


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Other Factors that Could Affect Cash Requirements


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


•cash collateral requirements that could exist in connection with certain contracts, including our weather hedging arrangements, and natural gas purchases, natural gas price and natural gas storage activities of ourCenterPoint Energy’s and CERC’s Natural Gas Distribution and Energy Services business segments;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;suppliers (CenterPoint Energy and CERC); 
•increased costs related to the acquisition of natural gas;gas (CenterPoint Energy and CERC); 
•increases in interest expense in connection with debt refinancings and borrowings under credit facilities;facilities or term loans or the use of alternative sources of financings on capital and other financial markets; 
•various legislative or regulatory actions;
•incremental collateral, if any, that may be required due to regulation of derivatives;derivatives (CenterPoint Energy and CERC); 
the ability of GenOn and its subsidiaries, currently the subject of bankruptcy proceedings, to satisfy their obligations in respect of GenOn’s indemnity obligations to us and our subsidiaries;

•the ability of REPs, including REP affiliates of NRG and Vistra Energy Corp., formerly known as TCEH Corp., to satisfy their obligations to usCenterPoint Energy and our subsidiaries;Houston Electric;

•slower customer payments and increased write-offs of receivables due to higher natural gas prices, or changing economic conditions;conditions, public health threats or severe weather events (CenterPoint Energy and CERC); 
•the satisfaction of any obligations pursuant to guarantees;
•the outcome of litigation, brought by or against us;including litigation related to the February 2021 Winter Storm Event;
•contributions to pension and postretirement benefit plans;


•restoration costs and revenue losses resulting from future natural disasters such as hurricanes and the timing of recovery of such restoration costs; and

•various other risks identified in “Risk Factors” in Item 1A of Part I of this report.


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 has contractually agreed that it will not issue additional firstand SIGECO are limited in the amount of mortgage bonds subject to certain exceptions.they can issue by the General Mortgage and SIGECO’s mortgage indenture, respectively. For information about the total debt to capitalization financial covenants in ourthe Registrants’ and SIGECO’s revolving credit facilities, see Note 13 to ourthe consolidated financial statements.


CRITICAL ACCOUNTING POLICIES


A critical accounting policy is one that is both important to the presentation of ourthe 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 ourthe 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 usthe Registrants to make assumptions about matters that are highly uncertain at the time the estimate is made. Additionally, different estimates that wethe 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 ourtheir financial condition, results of operations or cash flows. The circumstances that make these judgments difficult, subjective and/or complex have to do with the need to make estimates about the effect of matters that are inherently uncertain. Estimates and assumptions about future events and their effects cannot be predicted with certainty. WeThe Registrants base ourtheir estimates on historical experience and on various other assumptions that wethey 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 ourthe Registrants’ operating environment changes. OurThe Registrants’ significant accounting policies are discussed in Note 2 to ourthe consolidated financial statements. WeThe Registrants believe the following accounting policies involve the application of critical accounting estimates. Accordingly, these accounting estimates have been reviewed and discussed with the Audit Committee of theCenterPoint Energy’s Board of Directors.


Accounting for Rate Regulation


Accounting guidance for regulated operations provides that rate-regulated entities account for and report assets and liabilities consistent with the recovery of those incurred costs in rates if the rates established are designed to recover the costs of providing the regulated service and if the competitive environment makes it probable that such rates can be charged and collected. OurCenterPoint Energy, for its Electric Transmission & Distribution business segment and our Natural Gas Distribution business segmentreportable segments, Houston Electric and CERC apply this
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accounting guidance. Certain expenses and revenues subject to utility regulation or rate determination normally reflected in income are deferred on the balance sheet as regulatory assets or liabilities and are recognized in income as the related amounts are included in service rates and recovered from or refunded to customers. Regulatory assets and liabilities are recorded when it is probable that these items will be recovered or reflected in future rates. Determining probability requires significant judgment on the part of management and includes, but is not limited to, consideration of testimony presented in regulatory hearings, proposed regulatory decisions, final regulatory orders and the strength or status of applications for rehearing or state court appeals. If events were to occur that would make the recovery of these assets and liabilities no longer probable, wethe Registrants would be required to write off or write down these regulatory assets and liabilities. For further detail on ourthe Registrants’ regulatory assets and liabilities, see Note 67 to ourthe consolidated financial statements.


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


WeThe Registrants review the carrying value of our long-lived assets, including identifiable intangibles, goodwill, and equity method investments whenever events or changes in circumstances indicate that such carrying values may not be recoverable, and at least annually, goodwill is tested for goodwillimpairment as required by accounting guidance for goodwill and other intangible assets.  Unforeseen events, and changes in market conditions, and probable regulatory disallowances, where applicable, could have a material effect on the value of long-lived assets, including intangibles, goodwill, and equity method investments due to changes in estimates of future cash flows, interest rate, and regulatory matters, and could result in an impairment charge. A loss in value of an equity method investment is recognized when the decline is deemed to be other than temporary. WeThe Registrants recorded no goodwill impairments during 2017, 2016 and 2015. We did not record material impairments to long-lived assets, including intangibles,goodwill during 2017, 20162023, 2022 and 2015. We recorded impairments totaling $1,225 million to our equity method investment during 2015 and no impairment during 2017 and 2016. See Notes 9 and 10 to our consolidated financial statements for further discussion of the impairments recorded to our equity method investment in 2015.2021.



We performed our annual goodwill impairment test in the third quarter of 2017 and determined, based on the results of the first step, using the income approach, no impairment charge was required for any reporting unit.  Our reporting units approximate our reportable segments.


Fair value is the amount at which thean 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 or valuations by third parties, present value techniques based on estimates of cash flows, or multiples of earnings or revenue performance measures. The fair value of the asset could be different using different estimates and assumptions in these valuation techniques.


The determinationFair value measurements require significant judgment and unobservable inputs, including (i) projected timing and amount of fair value requires significant assumptions by management which are subjective and forward-looking in nature. To assist in making these assumptions, we utilized a third-party valuation specialist in both determining and testing key assumptions used in the valuation of each of our reporting units. We based our assumptions on projected financial information that we believe is reasonable; however, actual results may differ materially from those projections. These projectedfuture cash flows, which factor in planned growth initiatives, and for our Natural Gas Distribution reporting unit,(ii) the regulatory environment.environment, as applicable, and (iii) discount rates reflecting risk inherent in the future market prices. Determining the discount rates for the businesses that are not rate-regulated, such as for Energy Systems Group, requires the estimation of the appropriate company-specific risk premiums for such businesses based on evaluation of industry and entity-specific risks, which includes expectations about future market or economic conditions existing on the date of the impairment test. Changes in these assumptions could have a significant impact on results of the impairment tests.

Annual goodwill impairment test

CenterPoint Energy and CERC completed their 2023 annual goodwill impairment test during the third quarter of 2023 and determined, based on an income approach or a weighted combination of income and market approaches, that no goodwill impairment charge was required for any reporting unit. The fair values of our Natural Gas Distribution and Energy Serviceseach reporting unitsunit significantly exceeded the carrying values.value of the reporting unit.


Although there was not ano goodwill asset impairment in our 2017resulted from the 2023 annual test, an interim goodwill impairment test could be triggered by the following: actual earnings results that are materially lower than expected, significant adverse changes in the operating environment, an increase in the discount rate, changes in other key assumptions which require judgment and are forward looking in nature, or if ourCenterPoint Energy’s market capitalization falls below book value for an extended period of time. No impairment triggers were identified subsequenttime, or events affecting a reporting unit such as a contemplated disposal of all or part of a reporting unit.

Assets Held for Sale and Discontinued Operations

Generally, a long-lived asset to our 2017 annual test.

During the year ended December 31, 2015, we determined that an other than temporary decreasebe 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 of our investment in Enable had occurred. The impairment analysis compared theor their estimated fair value less cost to sell.If the disposal group reflects a component of our investment in Enablea reporting unit and meets the definition of a business, the goodwill within that reporting unit is allocated to its carrying value. Thethe disposal group based on the relative fair value of the investment was determined using multiple valuation methodologies under bothcomponents 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 marketdefinition of a business.A disposal group that meets the held for sale criteria and also represents a strategic shift to the Registrant is also reflected as discontinued operations on the Statements of Consolidated Income, and prior periods are recast to reflect the earnings or losses from such businesses as income approaches.from discontinued operations, net of tax.


Key assumptions
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As described further in Note 4 to the market approach include recent market transactionsconsolidated financial statements, certain assets and liabilities of comparable companies and EBITDA to total enterprise multiples for comparable companies. Due to volatilityEnergy Systems Group representing a business were disposed of the quoted price of Enable’s common units, a volume weighted average price was used under the market approach to best approximate fair value at the measurement date. Key assumptions in the income approach include Enable’s forecasted cash distributions, projected cash flows of incentive distribution rights, forecasted growth rate of Enable’s cash distributions beyond 2020, and the discount rate used to determine the present value of the estimated future cash flows. A weighing of the different approaches was utilized to determine the estimated fair value of our investment in Enable.

on June 30, 2023. As a result of the analysis, we recorded other than temporary impairments on our equity method investment in Enable of $1,225 millionheld for sale criteria being met during the year endedsame period as the completion of the sale, goodwill attributable to Energy Systems Group of $134 million was reflected in the pre-tax loss on sale of $13 million based on the actual sale proceeds received at closing on June 30, 2023.

Accounting for Securitization of Coal Generation Facility Retirements

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

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

For purposes of reporting cash flows, the Registrants consider cash equivalents to be short-term, highly-liquid investments with maturities of three months or less from the date of purchase. Cash and cash equivalents held by the SIGECO Securitization Subsidiary solely to support servicing the SIGECO Securitization Bonds as of December 31, 2015. We based our assumptions2023 are reflected on projected financial information that we believe is reasonable; however, actual results may differ materially from those projections. It is reasonably possible thatCenterPoint Energy’s Consolidated Balance Sheet.

In connection with the estimateissuance of the impairment of our equity method investment in Enable will changeSIGECO Securitization Bonds, CenterPoint Energy was required to establish a restricted cash account to collateralize the SIGECO Securitization Bonds that were issued in the near term due tofinancing transaction. The restricted cash account is not available for withdrawal until the following: actual Enablematurity of the SIGECO Securitization Bonds and is not included in cash distribution is materially lower than expected, significant adverse changes in Enable’s operating environment, increase in the discount rate, and changes in other key assumptions which require judgment and are forward-looking in nature.cash equivalents.


Unbilled Energy Revenues


Revenues related to electricity delivery and natural gas sales and services are generally recognized upon delivery to customers. However, the determination of deliveries to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month either electronically through AMS meter communications or manual readings. At the end of each month, deliveries to non-AMS customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is estimated. Information regarding deliveries to AMS customers after the last billing is obtained from actual AMS meter usage data. Unbilled electricity delivery revenue is estimated each month based on actual AMS meter data, daily supply volumes and applicable rates. Unbilled natural gas sales are estimated based on estimated purchased gas volumes, estimated lost and unaccounted for gas and tariffed rates in effect. As additional information becomes available, or actual amounts are determinable, the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates.


Pension and Other Retirement Plans


We sponsorCenterPoint Energy sponsors pension and other retirement plans in various forms covering all employees who meet eligibility requirements. We useCenterPoint Energy uses several statistical and other factors that attempt to anticipate future events in calculating the expense and liability related


to ourits plans. These factors include assumptions about the discount rate, expected return on plan assets and rate of future compensation increases as estimated by management, within certain guidelines. In addition, ourCenterPoint Energy’s actuarial consultants use subjective factors such as withdrawal and mortality rates. The actuarial assumptions used may differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal rates or longer or shorter life spans of participants. These differences may result in a significant impact to the
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amount of pension and other retirement plans expense recorded. Please read “— Other Significant Matters — Pension Plans” for further discussion.
 
NEW ACCOUNTING PRONOUNCEMENTS


See Note 2(p)2(t) to ourthe consolidated financial statements, incorporated herein by reference, for a discussion of new accounting pronouncements that affect us.the Registrants.


OTHER SIGNIFICANT MATTERS


Pension Plans.Plans (CenterPoint Energy).  As discussed in Note 7(b)8(b) to ourthe consolidated financial statements, we maintain aCenterPoint Energy maintains non-contributory qualified defined benefit pension planplans covering substantially alleligible employees. Employer contributions for the qualified planplans are based on actuarial computations that establish the minimum contribution required under ERISA and the maximum deductible contribution for income tax purposes.
Under the terms of ourCenterPoint Energy’s pension plan, we reserveplans, it reserves the right to change, modify or terminate the plan. OurCenterPoint Energy’s funding policy is to review amounts annually and contribute an amount at least equal to the minimum contribution required under ERISA.
The minimum funding requirements for the qualified pension plan were $39 million, $-0- and $-0- for 2017, 2016 and 2015, respectively. We made contributions of $39 million, $-0- million and $35 million in 2017, 2016 and 2015 for the respective years. We expect to contribute a minimum of approximately $60 million to the qualified pension plan in 2018.
Additionally, we maintain anCenterPoint Energy maintains unfunded non-qualified benefit restoration plan that allowsplans which allow participants to receive the benefits to which they would have been entitled under ourthe non-contributory qualified pension plan except for the federally mandated limits on qualified plan benefits or on the level of compensation on which qualified plan benefits may be calculated. Employer

CenterPoint Energy’s funding requirements and employer contributions for the years ended December 31, 2023, 2022 and 2021 were as follows:
Year Ended December 31,
202320222021
CenterPoint Energy(in millions)
Minimum funding requirements for qualified pension plans$— $— $— 
Employer contributions to the qualified pension plans24 27 53 
Employer contributions to the non-qualified benefit restoration plans8 8 8 

CenterPoint Energy expects to make contributions of approximately $2 million and $7 million to the qualified pension plans and non-qualified benefit restoration plan represent benefit payments made to participants and totaled $9 million, $9 million and $31 millionplans in 2017, 2016 and 2015,2024, respectively. We expect to make contributions aggregating approximately $7 million in 2018.

Changes in pension obligations and plan assets may not be immediately recognized as pension expense in the income statement,CenterPoint Energy’s Statements of Consolidated Income, but generally are recognized in future years over the remaining average service period of plan participants. As such, significant portions of pension expense recorded in any period may not reflect the actual level of benefit payments provided to plan participants.
As the sponsor of a plan, we areCenterPoint Energy is required to (a) recognize on our balance sheet asits Consolidated Balance Sheet an asset afor the plan’s over-funded status or as a liability suchfor the plan’s under-funded status, (b) measure a plan’s assets and obligations as of the end of ourthe fiscal year and (c) recognize changes in the funded status of ourthe plans in the year that changes occur through adjustments to other comprehensive income and, when related to its rate-regulated utilities with recoverability of cost, to regulatory assets.


The projected benefit obligation for all defined benefit pension plans was $2,225 million$1.5 billion and $2,197 million$1.6 billion as of December 31, 20172023 and 2016,2022, respectively. This decrease was primarily due to increases in discount rates, as well as the impact of lump sum settlement payments.


In December 2022, the CenterPoint Energy pension plan completed an annuity lift-out, a transaction that provided for the purchase of an irrevocable group annuity contract to fund pension plan annuities of retirees from previously divested businesses, as part of a de-risking strategy. This annuity lift-out impacted 1,119 retirees and beneficiaries, as well as reduced $138 million in pension obligations and $136 million in plan assets which were transferred to an insurance company. The transfer of plan assets is considered to be a lump sum settlement payment that reduced CenterPoint Energy pension plan’s projected benefit obligation in 2022.
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As of December 31, 2017,2023, the projected benefit obligation exceeded the market value of plan assets of ourCenterPoint Energy’s pension plans by $424$344 million. Changes in interest rates or the market values of the securities held by the plan during 2018a year could materially, positively or negatively, change ourthe funded status and affect the level of pension expense and required contributions.contributions at the next remeasurement.
Houston Electric and CERC participate in CenterPoint Energy’s qualified and non-qualified pension plans covering substantially all employees. Pension cost was $95 million, $102 million and $90 million for 2017, 2016 and 2015, respectively, of which $71 million, $67 million and $59 million impacted pre-tax earnings, respectively. Included in the 2015 pension costs was a $10 million settlement chargeby Registrant were as discussed below.follows:

Year Ended December 31,
202320222021
CenterPoint EnergyHouston ElectricCERCCenterPoint EnergyHouston ElectricCERCCenterPoint EnergyHouston ElectricCERC
(in millions)
Pension cost$53 $27 $19 $172 $59 $88 $69 $34 $24 
A one-time, non-cash settlement charge is required when lump sum distributions or other settlements of plan benefit obligations during the year exceed the service cost and interest cost components of net periodic cost for the year. Due to the amount of lump sum payment distributions from the non-qualified pension plan during the year ended December 31, 2015, CenterPoint Energy recognized a non-cash settlement charge of $10 million.  This charge is an acceleration of costs that would otherwise be recognized in future periods. 




The calculation of pension expensecost and related liabilities requires the use of assumptions. Changes in these assumptions can result in different expense and liability amounts, and future actual experience can differ from the assumptions. Two of the most critical assumptions are the expected long-term rate of return on plan assets and the assumed discount rate.
As of December 31, 2017, our2023, CenterPoint Energy’s qualified pension planplans had an expected long-term rate of return on plan assets of 6.00%6.50%, which is unchanged from the same as the 6.50% rate assumed as of December 31, 2016.2022. The expected rate of return assumption was developed using the targeted asset allocation of our plans and the expected return for each asset class. WeCenterPoint Energy regularly review ourreviews its actual asset allocation and periodically rebalancerebalances plan assets to reduce volatility and better match plan assets and liabilities.
As of December 31, 2017,2023, the projected benefit obligation was calculated assuming a discount rate of 3.65%4.95%, which is 0.50%0.2% lower than the 4.15%5.15% discount rate assumed as of December 31, 2016.2022 attributed primarily to rising interest rates. The discount rate was determined by reviewing yields on high-quality bonds that receive one of the two highest ratings given by a recognized rating agency and the expected duration of pension obligations specific to the characteristics of our plan.CenterPoint Energy’s plans.
OurCenterPoint Energy’s actuarially determined pension and other postemployment expensecost for 20172023 and 20162022 that is greater or less than the amounts being recovered through rates in certainthe majority of Texas jurisdictions is deferred as a regulatory asset or liability, respectively.  Pension cost for 2018,2024, including the nonqualified benefit restoration plan, is estimated to be $61$51 million of which we expect approximately $58 million to impact pre-tax earnings after effecting suchbefore applicable regulatory deferrals and capitalization, based on an expected return on plan assets of 6.00%6.50% and a discount rate of 3.65%4.95% as of December 31, 2017.2023. If the expected return assumption were lowered by 0.50% from 6.00%6.50% to 5.50%6.00%, 20182024 pension cost would increase by approximately $9$6 million.
As of December 31, 2017,2023, the pension planplans projected benefit obligation, including the unfunded benefit restoration plan,nonqualified pension plans, exceeded plan assets by $424$344 million.  If the discount rate were lowered by 0.50% from 3.65%4.95% to 3.15%4.45%, the assumption change would increase ourCenterPoint Energy’s projected benefit obligation by approximately $124$66 million and decrease our 2018its 2024 pension expensecost by approximately $2 million. The expected reduction in pension expensecost due to the decrease in discount rate is a result of the expected correlation between the reduced interest rate and appreciation of fixed income assets in pension plans with significantly more fixed income instruments than equity instruments. In addition, the assumption change would impact ourCenterPoint Energy’s Consolidated Balance SheetSheets by increasing the regulatory asset recorded as of December 31, 20172023 by $107$57 million and would result in a charge to comprehensive income in 20172023 of $13$7 million, net of tax.tax of $2 million, due to the increase in the projected benefit obligation.
Future changes in plan asset returns, assumed discount rates and various other factors related to the pension plans will impact ourCenterPoint Energy’s future pension expense and liabilities. WeCenterPoint Energy cannot predict with certainty what these factors will be in the future.


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Item 7A.     Quantitative and Qualitative Disclosures About Market Risk


Impact of Changes in Interest Rates, Equity Prices and Energy Commodity Prices


WeThe Registrants are exposed to various market risks. These risks arise from transactions entered into in the normal course of business and are inherent in ourthe Registrants’ consolidated financial statements. Most of the revenues and income from ourthe Registrants’ business activities are affected by market risks. Categories of market risk include exposure to commodity prices through non-trading activities, interest rates and equity prices. A description of each market risk is set forth below:


•Interest rate risk primarily results from exposures to changes in the level of borrowings and changes in interest rates.

•Equity price risk results from exposures to changes in prices of individual equity securities.securities (CenterPoint Energy).

•Commodity price risk results from exposures to changes in spot prices, forward prices and price volatilities of commodities, such as natural gas, NGLs and other energy commodities.commodities (CenterPoint Energy).


Management has established comprehensive risk management policies to monitor and manage these market risks.


Interest Rate Risk
 
As of December 31, 2017, we2023, the Registrants had outstanding long-term debt and lease obligations and CenterPoint Energy had obligations under ourits ZENS that subject usthem to the risk of loss associated with movements in market interest rates.


OurCenterPoint Energy’s floating rate obligations aggregated $1.8$1.9 billion and $1.4$4.5 billion as of December 31, 20172023 and 2016,2022, respectively. If the floating interest rates were to increase by 10%100 basis points from December 31, 20172023 rates, ourCenterPoint Energy’s combined interest expense would increase by $3approximately $19 million annually. CenterPoint Energy has $350 million aggregate principal amount of floating rate notes maturing in 2024 that will be refinanced at current rates.



Houston Electric did not have any floating rate obligations as of either December 31, 2023 or 2022.


CERC’s floating rate obligations aggregated $484 million and $1.4 billion as of December 31, 2023 and 2022, respectively. If the floating interest rates were to increase by 100 basis points from December 31, 2023 rates, CERC’s combined interest expense would increase by approximately $5 million annually. CERC has no floating rate notes maturing in 2024.

As of December 31, 20172023 and 2016, we2022, CenterPoint Energy had outstanding fixed-rate debt (excluding indexed debt securities) aggregating $7$16.9 billion and $7.1$12.5 billion, respectively, in principal amount and having a fair value of $7.5$16.1 billion and $7.5$11.1 billion, respectively. Because these instruments are fixed-rate, they do not expose usCenterPoint Energy to the risk of loss in earnings due to changes in market interest rates (see Note 13 to our consolidated financial statements).rates. However, the fair value of these instruments would increase by approximately $218$635 million if interest rates were to decline by 10% from their levels as of December 31, 2017. 2023. CenterPoint Energy has $500 million of fixed-rate senior notes and $23 million of SIGECO first mortgage bonds maturing in 2024 that will be refinanced at current rates.

As of December 31, 2023 and 2022, Houston Electric had outstanding fixed-rate debt aggregating $7.7 billion and $6.4 billion, respectively, in principal amount and having a fair value of approximately $7 billion and $5.6 billion, respectively. Because these instruments are fixed-rate, they do not expose Houston Electric to the risk of loss in earnings due to changes in market interest rates. However, the fair value of these instruments would increase by approximately $374 million if interest rates were to decline by 10% from their levels as of December 31, 2023. Houston Electric has no fixed-rate general mortgage bonds maturing in 2024.

As of December 31, 2023 and 2022, CERC had outstanding fixed-rate debt aggregating $4.2 billion and $3.5 billion, respectively, in principal amount and having a fair value of $4.2 billion and $3.3 billion, respectively. Because these instruments are fixed-rate, they do not expose CERC to the risk of loss in earnings due to changes in market interest rates. However, the fair value of these instruments would increase by approximately $152 million if interest rates were to decline by 10% from their levels at December 31, 2023. CERC has no fixed-rate senior notes maturing in 2024.

In general, such an increase in fair value would impact earnings and cash flows only if wethe Registrants were to reacquire all or a portion of these instruments in the open market prior to their maturity.


As discussed in Note 11 to ourthe consolidated financial statements, the ZENS obligation is bifurcated into a debt component and a derivative component. The debt component of $122$5 million at December 31, 20172023 was a fixed-rate obligation and, therefore, did not expose usCenterPoint Energy to the risk of loss in earnings due to changes in market interest rates. However,
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the fair value of the debt component would increase by approximately $19$1 million if interest rates were to decline by 10% from levels at December 31, 2017.2023. Changes in the fair value of the derivative component, a $668$605 million recorded liability at December 31, 2017,2023, are recorded in ourCenterPoint Energy’s Statements of Consolidated Income and, therefore, we areit is exposed to changes in the fair value of the derivative component as a result of changes in the underlying risk-free interest rate. If the risk-free interest rate were to increase by 10% from December 31, 20172023 levels, the fair value of the derivative component liability would increasedecrease by approximately $6$1 million, which would be recorded as an unrealized lossgain in ourCenterPoint Energy’s Statements of Consolidated Income.


Equity Market Value Risk (CenterPoint Energy)


We areCenterPoint Energy is exposed to equity market value risk through ourits ownership of 7.110.2 million shares of TWAT&T Common, 0.9 million shares of Time Common and 0.9 million shares of Charter Common and 2.5 million shares of WBD Common, which we holdCenterPoint Energy holds to facilitate ourits ability to meet ourits obligations under the ZENS. See Note 11 to ourthe consolidated financial statements for a discussion of ourCenterPoint Energy’s ZENS obligation. Changes in the fair value of the TWZENS-Related Securities held by CenterPoint Energy are expected to substantially offset changes in the fair value of the derivative component of the ZENS. A decrease of 10% from the December 31, 20172023 aggregate market value of these shares would result in a net loss of approximately $2less than $1 million, which would be recorded as an unrealizeda loss on debt securities in ourCenterPoint Energy’s Statements of Consolidated Income.


Commodity Price Risk From Non-Trading Activities (CenterPoint Energy)


We manage these risk exposures through the implementation of our risk management policies and framework. We manage ourCenterPoint Energy’s regulated operations are exposed to commodity price risk exposures through the use of derivative financial instruments and derivative commodity instrument contracts. During the normal course of business, we review our hedging strategies and determine the hedging approach we deem appropriate based upon the circumstances of each situation.

Derivative instrumentsduring severe weather events such as futures, forward contracts, swapshurricanes, tornadoes and options derive their value from underlying assets, indices, reference ratessevere winter weather conditions. Severe weather events can increase commodity prices related to natural gas, coal and purchased power, which may increase our costs of providing service, and those costs may not be recoverable in rates. Recovery of cost increases driven by rising commodity prices during severe weather events could be resisted by our regulators and our regulators might attempt to deny or a combinationdefer timely recovery of these factors. These derivative instruments include negotiated contracts, which are referred to as over-the-counter derivatives, and instruments that are listed and traded on an exchange.those costs.


Derivative transactions are entered intoHowever, CenterPoint Energy’s regulated operations in our non-trading operations to manage and hedge certain exposures, such asIndiana have limited exposure to changes in natural gas prices. We believe that the associated market risk of these instruments can best be understood relative to the underlying assets or risk being hedged.

We use derivative instruments as economic hedges to offset the commodity price exposure inherent in our businesses. The commodity risk created by these instruments, including the offsetting impact on the market valuefor transactions involving purchases and sales of natural gas, inventory, is described below. We measure this commodity riskcoal and purchased power for the benefit of retail customers due to current state regulations, which, subject to compliance with those regulations, allow for recovery of the cost of such purchases through natural gas and fuel cost adjustment mechanisms. CenterPoint Energy’s utility natural gas operations in Indiana have regulatory authority to lock in pricing for up to 50% of annual natural gas purchases using a sensitivity analysis. For purposesarrangements with an original term of this analysis, we estimate commodity price risk by applying a $0.50 change in the forward NYMEX priceup to our net open10 years. This authority has been utilized to secure fixed price position (including forward fixed price physical contracts, natural gas inventoryusing both physical purchases and fixed price financial contracts) at the end of each period.derivatives. As of December 31, 2017,2023, the recorded fair value of our non-trading energy derivativesderivative liability was a net asset of $111$12 million (before collateral), all offor CenterPoint Energy’s utility natural gas operations in Indiana, which is related to our Energy Services business segment. A $0.50 changeoffset by a regulatory asset.

Natural gas and coal prices have other effects on working capital requirements, interest costs, and some level of price-sensitivity in the forward NYMEX price would have had a combined impactvolumes sold or delivered. Constructive regulatory orders, such as those authorizing lost margin recovery, other innovative rate designs and recovery of $5 million on our non-trading energy derivatives net asset and the market value ofunaccounted for natural gas inventory.

Commodity price risk is not limited to changes in forward NYMEX prices. Variation of commodity pricing betweenand other natural gas-related expenses, also mitigate the different indices used to mark to market portions of oureffect natural gas inventory (Gas Daily) andcosts may have on CenterPoint Energy’s financial condition. In 2008, the related fair value hedge (NYMEX) can resultPUCO approved an exit of the merchant function in volatilityCenterPoint Energy’s Ohio natural gas service territory, allowing Ohio customers to our net income. Over time, any gains or losses on the sale of storagepurchase substantially all natural gas inventory would be offset by gains or losses on the fair value hedges.

directly from retail marketers rather than from CenterPoint Energy.

83


Item 8.        Financial Statements and Supplementary Data


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and the Board of Directors and Shareholders of
CenterPoint Energy, Inc.
Houston, Texas
Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of CenterPoint Energy, Inc. and subsidiaries (the "Company") as of December 31, 20172023 and 2016,2022, the related statements of consolidated income, comprehensive income, shareholders'changes in equity, and cash flows, for each of the three years in the period ended December 31, 2017,2023, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 20172023 and 2016,2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017,2023, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2017,2023, based on criteria established in Internal Control -— Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 22, 2018,20, 2024, expressed an unqualified opinion on the Company's internal control over financial reporting.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Impact of Rate Regulation on the Financial Statements — Refer to Note 7 to the financial statements

Critical Audit Matter Description

The Company is subject to rate regulation by regulators and commissions in various jurisdictions (collectively, the “Commissions”) that have jurisdiction with respect to the rates of electric and gas transmission and distribution companies in those jurisdictions. Management has determined its regulated operations meet the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. The impacts of accounting for the economics of rate regulation are pervasive to the financial statements and disclosures.

84

The Company’s rates are subject to regulatory rate-setting processes by the Commissions. Rates are determined and approved in regulatory proceedings based on an analysis of the Company’s costs to provide utility service and a return on, and recovery of, the Company’s investment in the utility business. Regulatory decisions can have an impact on the recovery of costs, the rate of return earned on investment, and the timing and amount of assets to be recovered in rates. The Commissions’ regulation of rates is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital. Decisions to be made by the Commissions in the future will impact the accounting for regulated operations, including decisions about the amount of allowable costs and return on invested capital included in rates and any refunds that may be required. While the Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that the Commissions will not approve: (1) full recovery of the costs of providing utility service, or (2) full recovery of all amounts invested in the utility business and a reasonable return on that investment.

We identified rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about certain affected account balances and disclosures and the high degree of subjectivity involved in assessing the impact of regulatory actions on the financial statements. Management’s judgments include assessing the likelihood of (1) recovery in future rates of incurred costs, (2) a disallowance of capital investments made by the Company and (3) refunds to customers. Given that certain of management’s accounting judgments are based on assumptions about the outcome of decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the potential uncertainty of decisions by the Commissions included the following, among others:

•We evaluated the Company’s disclosures related to the effects of rate regulation by testing certain recorded balances and evaluating regulatory developments.

•We read relevant regulatory orders issued by the Commissions, regulatory statutes, filings made by the Company and intervenors, and other external information. We evaluated relevant external information and compared it to certain recorded regulatory asset and liability balances for completeness.

•For certain regulatory matters, we inspected the Company’s filings with the Commissions and the filings with the Commissions by intervenors to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions’ treatment of similar costs under similar circumstances.


/s/ DELOITTE & TOUCHE LLP


Houston, Texas
February 22, 2018  20, 2024


We have served as the Company's auditor since 1932.







85

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED INCOME



 Year Ended December 31,
 2017 2016 2015
 (in millions, except per share amounts)
Revenues:     
Utility revenues$5,603
 $5,440
 $5,448
Non-utility revenues4,011
 2,088
 1,938
Total9,614
 7,528
 7,386
Expenses: 
    
Utility natural gas1,109
 983
 1,264
Non-utility natural gas3,785
 1,983
 1,838
Operation and maintenance2,221
 2,093
 2,007
Depreciation and amortization1,036
 1,126
 970
Taxes other than income taxes391
 384
 374
Total8,542
 6,569
 6,453
Operating Income1,072
 959
 933
Other Income (Expense):     
Gain (loss) on marketable securities7
 326
 (93)
Gain (loss) on indexed debt securities49
 (413) 74
Interest and other finance charges(313) (338) (352)
Interest on Securitization Bonds(77) (91) (105)
Equity in earnings (losses) of unconsolidated affiliates265
 208
 (1,633)
Other, net60
 35
 46
Total(9) (273) (2,063)
Income (Loss) Before Income Taxes1,063
 686
 (1,130)
Income tax expense (benefit)(729) 254
 (438)
Net Income (Loss)$1,792
 $432
 $(692)
      
Basic Earnings (Loss) Per Share$4.16
 $1.00
 $(1.61)
      
Diluted Earnings (Loss) Per Share$4.13
 $1.00
 $(1.61)
      
Weighted Average Shares Outstanding, Basic431
 431
 430
      
Weighted Average Shares Outstanding, Diluted434
 434
 430
 Year Ended December 31,
 202320222021
(in millions, except per share amounts)
Revenues:
Utility revenues$8,524 $9,018 $8,042 
Non-utility revenues172 303 310 
Total8,696 9,321 8,352 
Expenses:  
Utility natural gas, fuel and purchased power2,061 2,887 2,127 
Non-utility cost of revenues, including natural gas99 204 208 
Operation and maintenance2,850 2,833 2,810 
Depreciation and amortization1,401 1,288 1,316 
Taxes other than income taxes525 543 528 
Total6,936 7,755 6,989 
Operating Income1,760 1,566 1,363 
Other Income (Expense): 
Gain (loss) on equity securities31 (227)(172)
Gain (loss) on indexed debt securities(27)325 50 
Gain (loss) on sale(13)303 8 
Interest expense and other finance charges(684)(511)(508)
Interest expense on Securitization Bonds(17)(13)(21)
Other income (expense), net37 (26)58 
Total(673)(149)(585)
Income from Continuing Operations Before Income Taxes1,087 1,417 778 
Income tax expense170 360 110 
Income from Continuing Operations917 1,057 668 
Income from Discontinued Operations (net of tax expense of $-0-, $-0-, and $201, respectively)— — 818 
Net Income917 1,057 1,486 
Income allocated to preferred shareholders50 49 95 
Income Available to Common Shareholders$867 $1,008 $1,391 
Basic earnings per common share - continuing operations$1.37 $1.60 $0.97 
Basic earnings per common share - discontinued operations— — 1.38 
Basic Earnings Per Common Share$1.37 $1.60 $2.35 
Diluted earnings per common share - continuing operations$1.37 $1.59 $0.94 
Diluted earnings per common share - discontinued operations— — 1.34 
Diluted Earnings Per Common Share$1.37 $1.59 $2.28 
Weighted Average Common Shares Outstanding, Basic631 629 593 
Weighted Average Common Shares Outstanding, Diluted633 632 610 


See Combined Notes to Consolidated Financial Statements

86



CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME

 Year Ended December 31,
202320222021
 (in millions)
Net Income$917 $1,057 $1,486 
Other comprehensive income (loss): 
Adjustment to pension and other postemployment plans (net of tax expense (benefit) of ($1), $2 and $7, respectively)(5)32 21 
Net deferred gain from cash flow hedges (net of tax benefit of $-0-, $-0- and $-0-, respectively)1 — — 
Reclassification of deferred loss from cash flow hedges realized in net income (net of tax expense of $-0-, $-0- and $-0-, respectively)— 1 2 
Other comprehensive income (loss) from unconsolidated affiliates (net of tax of $-0-, $-0-, and $-0-, respectively)— — 3 
Total(4)33 26 
Comprehensive income913 1,090 $1,512 
Income allocated to preferred shareholders50 49 95 
Comprehensive income available to common shareholders$863 $1,041 $1,417 
 Year Ended December 31,
 2017 2016 2015
 (in millions)
Net income (loss)$1,792
 $432
 $(692)
Other comprehensive income (loss):   
  
Adjustment to pension and other postretirement plans (net of tax of $6, $4 and $12, respectively)6
 (7) 20
Net deferred gain (loss) from cash flow hedges (net of tax of $2, $-0-, and $-0-, respectively)(3) 1
 —
Reclassification of deferred loss from cash flow hedges realized in net income (net of tax of $-0-, $1, and $-0-, respectively)—
 1
 —
Other comprehensive income (loss)3
 (5) 20
Comprehensive income (loss)$1,795
 $427
 $(672)


See Combined Notes to Consolidated Financial Statements




87

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS



December 31,
2017		 December 31,
2016		 December 31,
2023		December 31,
2022
(in millions) (in millions)
ASSETS   
Current Assets:   
Cash and cash equivalents ($230 and $340 related to VIEs, respectively)$260
 $341
Investment in marketable securities960
 953
Accounts receivable ($73 and $52 related to VIEs, respectively), less bad debt reserve of $19 and $15, respectively1,000
 740
Accrued unbilled revenues427
 335
Natural gas inventory222
 131
Current Assets:
Current Assets:
Cash and cash equivalents ($90 and $75 related to VIEs, respectively)
Cash and cash equivalents ($90 and $75 related to VIEs, respectively)
Cash and cash equivalents ($90 and $75 related to VIEs, respectively)
Investment in equity securities
Accounts receivable ($21 and $22 related to VIEs, respectively), less allowance for credit losses of $27 and $38, respectively
Accounts receivable ($21 and $22 related to VIEs, respectively), less allowance for credit losses of $27 and $38, respectively
Accounts receivable ($21 and $22 related to VIEs, respectively), less allowance for credit losses of $27 and $38, respectively
Accrued unbilled revenues ($2 and $-0- related to VIEs, respectively), less allowance for credit losses of $2 and $4, respectively
Natural gas and coal inventory
Natural gas and coal inventory
Natural gas and coal inventory
Materials and supplies175
 181
Non-trading derivative assets110
 51
Taxes receivable—
 30
Prepaid expense and other current assets ($35 and $40 related to VIEs, respectively)241
 161
Regulatory assets
Regulatory assets
Regulatory assets
Prepaid expenses and other current assets ($15 and $13 related to VIEs, respectively)
Total current assets3,395
 2,923
Property, Plant and Equipment, net13,057
 12,307
Property, Plant and Equipment:
Property, plant and equipment
Property, plant and equipment
Property, plant and equipment
Less: accumulated depreciation and amortization
Property, plant and equipment, net
Other Assets: 
  
Other Assets:  
Goodwill867
 862
Regulatory assets ($1,590 and $1,919 related to VIEs, respectively)2,347
 2,677
Regulatory assets ($402 and $229 related to VIEs, respectively)
Non-trading derivative assets44
 19
Investment in unconsolidated affiliates2,472
 2,505
Preferred units - unconsolidated affiliate363
 363
Other191
 173
Non-trading derivative assets
Non-trading derivative assets
Other non-current assets
Other non-current assets
Other non-current assets
Total other assets6,284
 6,599
Total Assets$22,736
 $21,829


See Combined Notes to Consolidated Financial Statements

88


CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS, cont.


 December 31,
2023		December 31,
2022
 (in millions, except par value
 and shares)
LIABILITIES AND SHAREHOLDERS’ EQUITY  
Current Liabilities:  
Short-term borrowings$4 $511 
Current portion of VIE Securitization Bonds long-term debt178 156 
Indexed debt, net5 7 
Current portion of other long-term debt872 1,346 
Indexed debt securities derivative605 578 
Accounts payable917 1,352 
Taxes accrued291 298 
Interest accrued236 159 
Dividends accrued126 144 
Customer deposits111 110 
Non-trading derivative liabilities9 — 
Other510 452 
Total current liabilities3,864 5,113 
Other Liabilities:  
Deferred income taxes, net4,079 3,986 
Non-trading derivative liabilities3 — 
Benefit obligations572 547 
Regulatory liabilities3,208 3,245 
Other763 774 
Total other liabilities8,625 8,552 
Long-term Debt, net:  
VIE Securitization Bonds, net320 161 
Other long-term debt, net17,239 14,675 
Total long-term debt, net17,559 14,836 
Commitments and Contingencies (Note 15) 
Temporary Equity (Note 12)— 3 
Shareholders’ Equity:
Cumulative preferred stock, $0.01 par value, 20,000,000 shares authorized, no shares and 800,000 shares outstanding, respectively, $-0- and $800 liquidation preference, respectively (Note 12)— 790 
Common stock, $0.01 par value, 1,000,000,000 shares authorized, 631,225,829 shares and 629,535,631 shares outstanding, respectively6 6 
Additional paid-in capital8,604 8,568 
Retained earnings1,092 709 
Accumulated other comprehensive loss(35)(31)
Total shareholders’ equity9,667 10,042 
Total Liabilities and Shareholders’ Equity$39,715 $38,546 
 December 31,
2017
December 31,
2016
 (in millions, except par value
and shares)
LIABILITIES AND SHAREHOLDERS’ EQUITY 
  
Current Liabilities: 
  
Short-term borrowings$39
 $35
Current portion of VIE Securitization Bonds long-term debt434
 411
Indexed debt122
 114
Current portion of other long-term debt50
 500
Indexed debt securities derivative668
 717
Accounts payable963
 657
Taxes accrued181
 172
Interest accrued104
 108
Dividends accrued120
 —
Non-trading derivative liabilities20
 41
Other368
 325
Total current liabilities3,069
 3,080
Other Liabilities: 
  
Deferred income taxes, net3,174
 5,263
Non-trading derivative liabilities4
 5
Benefit obligations785
 913
Regulatory liabilities2,464
 1,298
Other357
 278
Total other liabilities6,784
 7,757
Long-term Debt: 
  
VIE Securitization Bonds, net1,434
 1,867
Other long-term debt, net6,761
 5,665
Total long-term debt, net8,195
 7,532
Commitments and Contingencies (Note 15) 

 

Shareholders’ Equity:   
Cumulative preferred stock, $0.01 par value, 20,000,000 shares authorized, none issued or outstanding—
 —
Common stock, $0.01 par value, 1,000,000,000 shares authorized, 431,044,845 shares and 430,682,504 shares outstanding, respectively4
 4
Additional paid-in capital4,209
 4,195
Retained earnings (accumulated deficit)543
 (668)
Accumulated other comprehensive loss(68) (71)
Total shareholders’ equity4,688
 3,460
Total Liabilities and Shareholders’ Equity$22,736
 $21,829


See Combined Notes to Consolidated Financial Statements

89


CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS

 Year Ended December 31,
 2017 2016 2015
 (in millions)
Cash Flows from Operating Activities:     
Net income (loss)$1,792
 $432
 $(692)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:   
  
Depreciation and amortization1,036
 1,126
 970
Amortization of deferred financing costs24
 26
 27
Deferred income taxes(770) 213
 (413)
Unrealized loss (gain) on marketable securities(7) (326) 93
Loss (gain) on indexed debt securities(49) 413
 (74)
Write-down of natural gas inventory—
 1
 4
Equity in (earnings) losses of unconsolidated affiliates, net of distributions(265) (208) 1,779
Pension contributions(48) (9) (66)
Changes in other assets and liabilities, excluding acquisitions: 
  
  
Accounts receivable and unbilled revenues, net(216) (117) 345
Inventory(7) 34
 28
Taxes receivable30
 142
 18
Accounts payable136
 133
 (224)
Fuel cost recovery(85) (72) 43
Non-trading derivatives, net(84) 30
 (7)
Margin deposits, net(55) 101
 (4)
Interest and taxes accrued5
 5
 (10)
Net regulatory assets and liabilities(107) (60) 63
Other current assets1
 (17) 10
Other current liabilities34
 22
 (50)
Other assets(4) (16) (5)
Other liabilities36
 30
 8
Other, net24
 48
 27
Net cash provided by operating activities1,421
 1,931
 1,870
Cash Flows from Investing Activities: 
  
  
Capital expenditures(1,426) (1,414) (1,584)
Acquisitions, net of cash acquired(132) (102) —
Decrease in notes receivable - unconsolidated affiliate—
 363
 —
Investment in preferred units - unconsolidated affiliate—
 (363) —
Distributions from unconsolidated affiliates in excess of cumulative earnings297
 297
 148
Decrease (increase) in restricted cash of Bond companies5
 (5) 12
Proceeds from sale of marketable securities—
 178
 32
Other, net(1) —
 5
Net cash used in investing activities(1,257) (1,046) (1,387)
Cash Flows from Financing Activities: 
  
  
Increase (decrease) in short-term borrowings, net4
 (5) (13)
Proceeds from commercial paper, net349
 469
 403
Proceeds from long-term debt, net1,096
 600
 200
Payments of long-term debt(1,211) (1,218) (644)
Loss on reacquired debt(5) (22) —
Debt issuance costs(13) (9) —
Payment of dividends on common stock(461) (443) (426)
Distribution to ZENS holders—
 (178) (32)
Other, net(4) (2) (5)
Net cash used in financing activities(245) (808) (517)
Net Increase (Decrease) in Cash and Cash Equivalents(81) 77
 (34)
Cash and Cash Equivalents at Beginning of Year341
 264
 298
Cash and Cash Equivalents at End of Year$260
 $341
 $264
      
 Year Ended December 31,

202320222021
 (in millions)
Cash Flows from Operating Activities: 
Net income$917 $1,057 $1,486 
Adjustments to reconcile net income to net cash provided by operating activities: 
Depreciation and amortization1,401 1,288 1,316 
Deferred income taxes31 20 213 
Loss (gain) on divestitures13 (303)(681)
Loss (gain) on equity securities(31)227 172 
Loss (gain) on indexed debt securities27 (325)(50)
Equity in earnings of unconsolidated affiliates— — (339)
Distributions from unconsolidated affiliates— — 155 
Pension contributions(32)(35)(61)
Changes in other assets and liabilities:   
Accounts receivable and unbilled revenues, net423 (461)(98)
Inventory167 (259)(140)
Taxes receivable(74)(19)81 
Accounts payable(302)203 175 
Net regulatory assets and liabilities1,043 234 (2,295)
Other current assets and liabilities162 (5)56 
Other non-current assets and liabilities72 109 (53)
Other operating activities, net60 79 85 
Net cash provided by operating activities3,877 1,810 22 
Cash Flows from Investing Activities:   
Capital expenditures(4,401)(4,419)(3,164)
Transaction costs related to Enable Merger (Note 4)— — (49)
Cash received related to Enable Merger— — 5 
Proceeds from sale of equity securities, net of transaction costs— 702 1,320 
Proceeds from divestitures (Note 4)144 2,075 22 
Other investing activities, net24 14 15 
Net cash used in investing activities(4,233)(1,628)(1,851)
Cash Flows from Financing Activities:   
Increase (decrease) in short-term borrowings, net(10)452 (27)
Payment of obligation for finance lease— (485)(179)
Proceeds from (payments of) commercial paper, net(1,055)(74)1,132 
Proceeds from long-term debt and term loans6,044 2,089 4,493 
Payments of long-term debt and term loans, including make-whole premiums(3,190)(1,795)(2,968)
Payment of debt issuance costs(55)(36)(38)
Payment of dividends on Common Stock(485)(440)(385)
Payment of dividends on Preferred Stock(50)(49)(107)
Redemption of Series A Preferred Stock(800)— — 
Other financing activities, net(25)(7)(5)
Net cash provided by (used in) financing activities374 (345)1,916 
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash18 (163)87 
Cash, Cash Equivalents and Restricted Cash at Beginning of Year91 254 167 
Cash, Cash Equivalents and Restricted Cash at End of Year$109 $91 $254 


See Combined Notes to Consolidated Financial Statements

90


CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS, cont.CHANGES IN EQUITY

 Year Ended December 31,
 2017 2016 2015
 (in millions)
Supplemental Disclosure of Cash Flow Information: 
  
  
Cash Payments: 
  
  
Interest, net of capitalized interest$378
 $406
 $426
Income taxes (refunds), net15
 (104) (45)
Non-cash transactions:   
  
Accounts payable related to capital expenditures144
 87
 95

 202320222021
 SharesAmountSharesAmountSharesAmount
 (in millions of dollars and shares, except authorized shares and per share amounts)
Cumulative Preferred Stock, $0.01 par value; authorized 20,000,000 shares
Balance, beginning of year1 $790 1 $790 3 $2,363 
Conversion of Series B Preferred Stock and Series C Preferred Stock— — — — (2)(1,573)
Redemption of Series A Preferred Stock(1)(790)— — — — 
Balance, end of year— — 1 790 1 790 
Common Stock, $0.01 par value; authorized 1,000,000,000 shares      
Balance, beginning of year630 6 629 6 551 6 
Issuances related to benefit and investment plans1 — 1 — 1 — 
Issuances of Common Stock— — — — 77 — 
Balance, end of year631 6 630 6 629 6 
Additional Paid-in-Capital  
Balance, beginning of year8,568  8,529 6,914 
Issuances related to benefit and investment plans36  39 41 
Issuances of Common Stock, net of issuance costs—  — 1 
Conversion of Series B Preferred Stock and Series C Preferred Stock— — 1,573 
Balance, end of year8,604  8,568 8,529 
Retained Earnings (Accumulated Deficit)    
Balance, beginning of year709  154 (845)
Net income (loss)917  1,057 1,486 
Common Stock dividends declared (see Note 12)(492) (453)(404)
Series A Preferred Stock dividends declared (see Note 12)(42)(49)(49)
Series B Preferred Stock dividends declared (see Note 12)— — (34)
Balance, end of year1,092  709 154 
Accumulated Other Comprehensive Loss    
Balance, beginning of year(31) (64)(90)
Other comprehensive income(4) 33 26 
Balance, end of year(35) (31)(64)
Total Shareholders’ Equity$9,667  $10,042 $9,415 
See Combined Notes to Consolidated Financial Statements

91



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Member of
CenterPoint Energy Houston Electric, LLC

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of CenterPoint Energy Houston Electric, LLC and subsidiaries (an indirect wholly-owned subsidiary of CenterPoint Energy, Inc.) (the "Company") as of December 31, 2023 and 2022, the related statements of consolidated income, comprehensive income, changes in equity, and cash flows, for each of the three years in the period ended December 31, 2023, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Impact of Rate Regulation on the Financial Statements — Refer to Note 7 to the financial statements

Critical Audit Matter Description

The Company is subject to rate regulation by the Public Utility Commission of Texas (“PUCT”), which has jurisdiction with respect to the rates of electric transmission and distribution companies in Texas. Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. The impacts of accounting for the economics of rate regulation are pervasive to the financial statements and disclosures.

The Company’s rates are subject to regulatory rate-setting processes by the PUCT. Rates are determined and approved in regulatory proceedings based on an analysis of the Company’s costs to provide utility service and a return on, and recovery of, the Company’s investment in the utility business. Regulatory decisions can have an impact on the recovery of costs, the rate of return earned on investment, and the timing and amount of assets to be recovered in rates. The PUCT’s regulation of rates is
92

premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital. Decisions to be made by the PUCT in the future will impact the accounting for regulated operations, including decisions about the amount of allowable costs and return on invested capital included in rates and any refunds that may be required. While the Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that the PUCT will not approve: (1) full recovery of the costs of providing utility service, or (2) full recovery of all amounts invested in the utility business and a reasonable return on that investment.

We identified rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about certain affected account balances and disclosures and the high degree of subjectivity involved in assessing the impact of regulatory actions on the financial statements. Management’s judgments include assessing the likelihood of (1) recovery in future rates of incurred costs, (2) a disallowance of capital investments made by the Company, and (3) refunds to customers. Given that certain of management’s accounting judgments are based on assumptions about the outcome of decisions by the PUCT, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the potential uncertainty of decisions by the PUCT included the following, among others:

•We evaluated the Company’s disclosures related to the effects of rate regulation by testing certain recorded balances and evaluating regulatory developments.

•We read relevant regulatory orders issued by the PUCT, regulatory statutes, filings made by the Company and intervenors, and other external information. We evaluated relevant external information and compared it to certain recorded regulatory asset and liability balances for completeness.

•For certain regulatory matters, we inspected the Company’s filings with the Commissions and the filings with the PUCT by intervenors to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the PUCT’s treatment of similar costs under similar circumstances.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas
February 20, 2024

We have served as the Company's auditor since 1932.
93

CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC AND SUBSIDIARIES
(An Indirect, Wholly-Owned Subsidiary of CenterPoint Energy, Inc.)

STATEMENTS OF CONSOLIDATED INCOME


 Year Ended December 31,
 202320222021
 (in millions)
Revenues$3,677 $3,412 $3,134 
Expenses:   
Operation and maintenance1,673 1,650 1,597 
Depreciation and amortization748 670 642 
Taxes other than income taxes262 261 251 
Total2,683 2,581 2,490 
Operating Income994 831 644 
Other Income (Expense):   
Interest expense and other finance charges(259)(202)(183)
Interest expense on Securitization Bonds(8)(13)(21)
Other income, net34 19 17 
Total(233)(196)(187)
Income Before Income Taxes761 635 457 
Income tax expense168 125 76 
Net Income$593 $510 $381 

See Combined Notes to Consolidated Financial Statements

94

CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC AND SUBSIDIARIES
(An Indirect, Wholly-Owned Subsidiary of CenterPoint Energy, Inc.)

CONSOLIDATED BALANCE SHEETS
 December 31, 2023December 31, 2022
 (in millions)
ASSETS 
Current Assets: 
Cash and cash equivalents ($76 and $75 related to VIEs, respectively)$76 $75 
Accounts and notes receivable, net ($19 and $22 related to VIEs, respectively), less allowance for credit losses of $1 and $1, respectively295 311 
Accounts and notes receivable—affiliated companies251 21 
Accrued unbilled revenues142 142 
Materials and supplies409 471 
Taxes receivable38 — 
Prepaid expenses and other current assets ($13 and $13 related to VIEs, respectively)48 41 
Total current assets1,259 1,061 
Property, Plant and Equipment, net
Property, plant and equipment19,515 17,753 
Less: accumulated depreciation and amortization4,469 4,292 
Property, plant and equipment, net15,046 13,461 
Other Assets:  
Regulatory assets ($74 and $229 related to VIEs, respectively)752 778 
Other non-current assets29 39 
Total other assets781 817 
Total Assets$17,086 $15,339 

See Combined Notes to Consolidated Financial Statements



























95





CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC AND SUBSIDIARIES
(AN INDIRECT, WHOLLY-OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.)
CONSOLIDATED BALANCE SHEETS – (continued)


LIABILITIES AND MEMBER’S EQUITY

December 31, 2023December 31, 2022
(in millions)
LIABILITIES AND MEMBER’S EQUITY  
Current Liabilities:  
Current portion of VIE Securitization Bonds long-term debt$161 $156 
Accounts payable351 413 
Accounts and notes payable—affiliated companies104 755 
Taxes accrued155 150 
Interest accrued99 83 
Other current liabilities111 88 
Total current liabilities981 1,645 
Other Liabilities:
Deferred income taxes, net1,406 1,229 
Benefit obligations32 38 
Regulatory liabilities1,025 1,155 
Other non-current liabilities107 77 
Total other liabilities2,570 2,499 
Long-Term Debt, net:
VIE Securitization Bonds, net— 161 
Other long-term debt, net7,426 6,036 
Total long-term debt, net7,426 6,197 
Commitments and Contingencies (Note 15)
Member’s Equity:
Common stock— — 
Additional paid-in capital4,745 3,860 
Retained earnings1,364 1,138 
Total member’s equity6,109 4,998 
Total Liabilities and Member’s Equity$17,086 $15,339 


See Combined Notes to Consolidated Financial Statements
96

CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC AND SUBSIDIARIES
(An Indirect, Wholly-Owned Subsidiary of CenterPoint Energy, Inc.)

STATEMENTS OF CONSOLIDATED CASH FLOWS


 Year Ended December 31,

202320222021
 (in millions)
Cash Flows from Operating Activities: 
Net income$593 $510 $381 
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization748 670 642 
Deferred income taxes160 86 32 
Changes in other assets and liabilities:  
Accounts and notes receivable, net16 (63)(17)
Accounts receivable/payable–affiliated companies(1)47 (36)
Inventory62 (179)(97)
Accounts payable(60)(7)66 
Taxes receivable(38)— — 
Net regulatory assets and liabilities(130)(41)(237)
Other current assets and liabilities28 (20)39 
Other non-current assets and liabilities35 (25)6 
Other operating activities, net(12)(12)(9)
Net cash provided by operating activities1,401 966 770 
Cash Flows from Investing Activities:   
Capital expenditures(2,279)(2,436)(1,619)
Increase in notes receivable–affiliated companies(238)— — 
Other investing activities, net14 1 2 
Net cash used in investing activities(2,503)(2,435)(1,617)
Cash Flows from Financing Activities:   
Proceeds from long-term debt1,398 1,589 1,096 
Payments of long-term debt(156)(720)(613)
Dividend to parent(367)(316)— 
Increase (decrease) in notes payable–affiliated companies
(642)130 504 
Payment of debt issuance costs(13)(17)(12)
Contribution from parent885 1,143 130 
Payment of obligation for finance lease— (485)(179)
Other financing activities, net(2)— — 
Net cash provided by financing activities1,103 1,324 926 
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash1 (145)79 
Cash, Cash Equivalents and Restricted Cash at Beginning of the Year88 233 154 
Cash, Cash Equivalents and Restricted Cash at End of the Year$89 $88 $233 

See Combined Notes to Consolidated Financial Statements

97

CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC AND SUBSIDIARIES
(An Indirect, Wholly-Owned Subsidiary of CenterPoint Energy, Inc.)

STATEMENTS OF CONSOLIDATED CHANGES IN EQUITY


 202320222021
 SharesAmountSharesAmountSharesAmount
 (in millions, except share amounts)
Common Stock      
Balance, beginning of year1,000 $— 1,000 $— 1,000 $— 
Balance, end of year1,000 — 1,000 — 1,000 — 
Additional Paid-in-Capital    
Balance, beginning of year3,860  2,678 2,548 
Non-cash contribution from parent— 38 — 
Contribution from parent885 1,143 130 
Other— 1 — 
Balance, end of year4,745  3,860 2,678 
Retained Earnings    
Balance, beginning of year1,138  944 563 
Net income593  510 381 
Dividend to parent(367)(316)— 
Balance, end of year1,364  1,138 944 
Total Member’s Equity$6,109  $4,998 $3,622 

See Combined Notes to Consolidated Financial Statements

98

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Stockholder of
CenterPoint Energy Resources Corp.

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of CenterPoint Energy Resources Corp. and subsidiaries (an indirect wholly-owned subsidiary of CenterPoint Energy, Inc.) (the "Company") as of December 31, 2023 and 2022, the related statements of consolidated income, comprehensive income, changes in equity, and cash flows, for each of the three years in the period ended December 31, 2023, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Impact of Rate Regulation on the Financial Statements — Refer to Note 7 to the financial statements

Critical Audit Matter Description

The Company is subject to rate regulation by regulators and commissions in various jurisdictions (collectively, the “Commissions”) that have jurisdiction with respect to the rates of gas transmission and distribution companies in those jurisdictions. Management has determined its regulated operations meet the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. The impacts of accounting for the economics of rate regulation are pervasive to the financial statements and disclosures.

The Company’s rates are subject to regulatory rate-setting processes by the Commissions. Rates are determined and approved in regulatory proceedings based on an analysis of the Company’s costs to provide utility service and a return on, and recovery of, the Company’s investment in the utility business. Regulatory decisions can have an impact on the recovery of costs, the rate
99

of return earned on investment, and the timing and amount of assets to be recovered in rates. The Commissions’ regulation of rates is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital. Decisions to be made by the Commissions in the future will impact the accounting for regulated operations, including decisions about the amount of allowable costs and return on invested capital included in rates and any refunds that may be required. While the Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that the Commissions will not approve: (1) full recovery of the costs of providing utility service, or (2) full recovery of all amounts invested in the utility business and a reasonable return on that investment.

We identified rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about certain affected account balances and disclosures and the high degree of subjectivity involved in assessing the impact of regulatory actions on the financial statements. Management’s judgments include assessing the likelihood of (1) recovery in future rates of incurred costs, (2) a disallowance of capital investments made by the Company and (3) refunds to customers. Given that certain of management’s accounting judgments are based on assumptions about the outcome of decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the potential uncertainty of decisions by the Commissions included the following, among others:

•We evaluated the Company’s disclosures related to the effects of rate regulation by testing certain recorded balances and evaluating regulatory developments.

•We read relevant regulatory orders issued by the Commissions, regulatory statutes, filings made by the Company and intervenors, and other external information. We evaluated relevant external information and compared it to certain recorded regulatory asset and liability balances for completeness.

•For certain regulatory matters, we inspected the Company’s filings with the Commissions and the filings with the Commissions by intervenors to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions’ treatment of similar costs under similar circumstances.


/s/ DELOITTE & TOUCHE LLP

Houston, Texas
February 20, 2024

We have served as the Company's auditor since 1997.
100

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(An Indirect, Wholly-Owned Subsidiary of CenterPoint Energy, Inc.)

STATEMENTS OF CONSOLIDATED INCOME


 Year Ended December 31,
 202320222021
 (in millions)
Revenues:
Utility revenues$4,107 $4,764 $4,143 
Non-utility revenues42 36 57 
Total4,149 4,800 4,200 
Expenses:   
Utility natural gas1,856 2,607 1,885 
Non-utility cost of revenue, including natural gas3 4 17 
Operation and maintenance904 886 973 
Depreciation and amortization493 448 483 
Taxes other than income taxes243 257 249 
Total3,499 4,202 3,607 
Operating Income650 598 593 
Other Income (Expense):   
Gain on sale— 557 11 
Interest expense and other finance charges(178)(130)(134)
Other income (expense), net14 (64)(4)
Total(164)363 (127)
Income Before Income Taxes486 961 466 
Income tax expense (benefit)(26)236 76 
Net Income$512 $725 $390 



See Combined Notes to Consolidated Financial Statements

101

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(An Indirect, Wholly-Owned Subsidiary of CenterPoint Energy, Inc.)

STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME


 Year Ended December 31,
202320222021
 (in millions)
Net income$512 $725 $390 
Other comprehensive income:   
Adjustment to other postemployment plans (net of tax expense of $-0-, $4 and $1, respectively)— 6 — 
Other comprehensive income— 6 — 
Comprehensive income$512 $731 $390 



See Combined Notes to Consolidated Financial Statements

102

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(An Indirect, Wholly-Owned Subsidiary of CenterPoint Energy, Inc.)

CONSOLIDATED BALANCE SHEETS


 December 31, 2023December 31, 2022
 (in millions)
ASSETS 
Current Assets:
 
Cash and cash equivalents$1 $— 
Accounts receivable, less allowance for credit losses of $25 and $34, respectively356 463 
Accrued unbilled revenue, less allowance for credit losses of $1 and $4, respectively329 573 
Accounts and notes receivable — affiliated companies43 52 
Material and supplies107 98 
Natural gas inventory156 195 
Non-trading derivative assets— 7 
Taxes receivable101 12 
Regulatory assets161 1,336 
Prepaid expenses and other current assets55 78 
Total current assets1,309 2,814 
Property, Plant and Equipment:
Property, plant and equipment15,672 14,379 
Less: accumulated depreciation and amortization4,169 3,973 
Property, plant and equipment, net11,503 10,406 
Other Assets:  
Goodwill1,583 1,583 
Regulatory assets850 844 
Non-trading derivative assets— 2 
Other non-current assets51 55 
Total other assets2,484 2,484 
Total Assets$15,296 $15,704 

See Combined Notes to Consolidated Financial Statements

103

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(An Indirect, Wholly-Owned Subsidiary of CenterPoint Energy, Inc.)

CONSOLIDATED BALANCE SHEETS, cont.


 December 31, 2023December 31, 2022
 (in millions)
LIABILITIES AND STOCKHOLDER’S EQUITY 
Current Liabilities:  
Short-term borrowings$4 $511 
Current portion of long-term debt— 1,331 
Accounts payable392 690 
Accounts and notes payable–affiliated companies99 190 
Taxes accrued145 140 
Interest accrued70 50 
Customer deposits95 94 
Non-trading derivative liabilities8 — 
Other current liabilities274 200 
Total current liabilities1,087 3,206 
Other Liabilities:  
Deferred income taxes, net1,246 1,262 
Non-trading derivative liabilities3 — 
Benefit obligations74 76 
Regulatory liabilities1,882 1,801 
Other non-current liabilities455 501 
Total other liabilities3,660 3,640 
Long-Term Debt, net4,670 3,495 
 
Commitments and Contingencies (Note 15)
Stockholder’s Equity:
Common stock— — 
Additional paid-in capital4,229 3,729 
Retained earnings1,634 1,618 
Accumulated other comprehensive income16 16 
Total stockholder’s equity5,879 5,363 
Total Liabilities and Stockholder’s Equity$15,296 $15,704 


See Combined Notes to Consolidated Financial Statements
104

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(An Indirect, Wholly-Owned Subsidiary of CenterPoint Energy, Inc.)

STATEMENTS OF CONSOLIDATED CASH FLOWS

 Year Ended December 31,

202320222021
 (in millions)
Cash Flows from Operating Activities: 
Net income$512 $725 $390 
Adjustments to reconcile net income to net cash provided by operating activities:   
Depreciation and amortization493 448 483 
Deferred income taxes(41)178 101 
Gain on divestitures— (557)(11)
Changes in other assets and liabilities:   
Accounts receivable and unbilled revenues, net410 (376)(68)
Accounts receivable/payable–affiliated companies(81)41 27 
Inventory101 (50)(62)
Taxes receivable(89)— (28)
Accounts payable(250)190 95 
Net regulatory assets and liabilities1,152 244 (2,095)
Other current assets and liabilities85 13 (39)
Other non-current assets and liabilities(1)(2)(31)
Other operating activities, net21 2 19 
Net cash provided by (used in) operating activities2,312 856 (1,219)
Cash Flows from Investing Activities:   
Capital expenditures(1,619)(1,661)(1,324)
Increase in notes receivable–affiliated companies(1)— — 
Proceeds from divestitures (Note 4)— 2,075 22 
Other investing activities, net(23)(8)15 
Net cash provided by (used in) investing activities(1,643)406 (1,287)
Cash Flows from Financing Activities:   
Increase (decrease) in short-term borrowings, net(10)452 (27)
Proceeds from (payments of) commercial paper, net(321)(94)552 
Proceeds from long-term debt and term loans2,006 927 1,699 
Payments of long-term debt and term loans, including make-whole premiums(2,332)(475)(311)
Payment of debt issuance costs(14)(14)(10)
Dividends to parent(496)(844)(17)
Contribution from parent500 289 140 
Increase (decrease) in notes payable–affiliated companies— (1,517)490 
Other financing activities, net(1)(1)(1)
Net cash provided by (used in) financing activities(668)(1,277)2,515 
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash1 (15)9 
Cash, Cash Equivalents and Restricted Cash at Beginning of Year— 15 6 
Cash, Cash Equivalents and Restricted Cash at End of Year$1 $— $15 

See Combined Notes to Consolidated Financial Statements
105

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(An Indirect, Wholly-Owned Subsidiary of CenterPoint Energy, Inc.)

STATEMENTS OF CONSOLIDATED CHANGES IN EQUITY


 202320222021
 SharesAmountSharesAmountSharesAmount
 (in millions, except share amounts)
Common Stock  
Balance, beginning of year1,000 $— 1,000 $— 1,000 $— 
Balance, end of year1,000 — 1,000 — 1,000 — 
Additional Paid-in-Capital    
Balance, beginning of year3,729  4,106 3,966 
Non-cash contribution from parent— 54 — 
Contribution from parent500 289 140 
Contribution to parent for sale of Arkansas and Oklahoma Natural Gas businesses— (720)— 
Balance, end of year4,229  3,729 4,106 
Retained Earnings    
Balance, beginning of year1,618  1,017 644 
Net income512  725 390 
Dividend to parent(496) (124)(17)
Balance, end of year1,634  1,618 1,017 
Accumulated Other Comprehensive Income    
Balance, beginning of year16  10 10 
Other comprehensive income— 6 — 
Balance, end of year16  16 10 
Total Stockholder’s Equity$5,879  $5,363 $5,133 



See Combined Notes to Consolidated Financial Statements

106

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED SHAREHOLDERS’ EQUITY
 2017 2016 2015
 Shares Amount Shares Amount Shares Amount
 (in millions of dollars and shares, except per share amounts)
Preference Stock, none outstanding—
 $—
 —
 $—
 —
 $—
Cumulative Preferred Stock, $0.01 par value; authorized 20,000,000 shares, none outstanding—
 —
 —
 —
 —
 —
Common Stock, $0.01 par value; authorized 1,000,000,000 shares 
  
  
  
  
  
Balance, beginning of year431
 4
 430
 4
 430
 4
Issuances related to benefit and investment plans—
 —
 1
 —
 —
 —
Balance, end of year431
 4
 431
 4
 430
 4
Additional Paid-in-Capital     
  
    
Balance, beginning of year  4,195
  
 4,180
   4,169
Issuances related to benefit and investment plans  14
  
 15
   11
Balance, end of year  4,209
  
 4,195
   4,180
Retained Earnings (Accumulated Deficit)   
  
  
    
Balance, beginning of year  (668)  
 (657)   461
Net income (loss)  1,792
  
 432
   (692)
Common stock dividends declared ($1.3475, $1.03 and $0.99 per share, respectively)  (581)  
 (443)   (426)
Balance, end of year  543
  
 (668)   (657)
Accumulated Other Comprehensive Loss   
  
  
    
Balance, end of year:   
  
  
    
Adjustment to pension and postretirement plans  (66)  
 (72)   (65)
Net deferred gain (loss) from cash flow hedges  (2)  
 1
   (1)
Total accumulated other comprehensive loss, end of year  (68)  
 (71)   (66)
Total Shareholders’ Equity  $4,688
  
 $3,460
   $3,461
See Notes to Consolidated Financial Statements



CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC AND SUBSIDIARIES
CENTERPOINT ENERGY INC.RESOURCES CORP. AND SUBSIDIARIES


COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


(1) Background


General. This combined Form 10-K is filed separately by three registrants: CenterPoint Energy, Inc., CenterPoint Energy Houston Electric, LLC and CenterPoint Energy Resources Corp. Information contained herein relating to any individual registrant is filed by such registrant solely on its own behalf. Each registrant makes no representation as to information relating exclusively to the other Registrants or the subsidiaries of CenterPoint Energy other than itself or its subsidiaries.

Except as discussed in Note 13 to the Registrants’ Consolidated Financial Statements, no registrant has an obligation in respect of any other Registrant’s debt securities, and holders of such debt securities should not consider the financial resources or results of operations of any Registrant other than the obligor in making a decision with respect to such securities.

Included in this combined Form 10-K are the Financial Statements of CenterPoint Energy, Houston Electric and CERC, which are referred to collectively as the Registrants. The Combined Notes to the Consolidated Financial Statements apply to all Registrants and specific references to Houston Electric and CERC herein also pertain to CenterPoint Energy, unless otherwise indicated.

Background.CenterPoint Energy, Inc. is a public utility holding company. On June 30, 2023, CenterPoint Energy completed the sale of its indirect subsidiary, Energy Systems Group, to an unaffiliated third party. For additional information, see Note 4.

As of December 31, 2023, CenterPoint Energy’s operating subsidiaries ownwere as follows:

•Houston Electric owns and operateoperates electric transmission and distribution and natural gas distribution facilities supply natural gas to commercial and industrial customers and electric and natural gas utilities and own interests in Enable as described below. CenterPoint Energy’s indirect, wholly-owned subsidiaries include:

Houston Electric, which engages in the electric transmission and distribution business in the Texas Gulf Coastgulf coast area that includes the city of Houston;


•CERC Corp., which (i) directly owns and operates natural gas distribution systems in six states;Louisiana, Minnesota, Mississippi and

CES, which obtains Texas, (ii) indirectly, through Indiana Gas and offers competitive variableVEDO, owns and fixed-price physicaloperates natural gas suppliesdistribution systems in Indiana and Ohio, respectively, and (iii) owns and operates permanent pipeline connections through interconnects with various interstate and intrastate pipeline companies through CEIP; and

•SIGECO provides energy delivery services primarily to commercial and industrial customers and electric and natural gas utilitiescustomers located in 33 states.and near Evansville in southwestern Indiana and owns and operates electric generation assets to serve its electric customers and optimizes those assets in the wholesale power market.

As of December 31, 2017, CenterPoint Energy also owned an aggregate of 14,520,000 Series A Preferred Units in Enable, which owns, operates and develops natural gas and crude oil infrastructure assets, and CERC Corp. owned approximately 54.1% of the common units representing limited partner interests in Enable.


For a description of CenterPoint Energy’s reportable business segments, see Note 18.17. Houston Electric and CERC each consist of a single reportable segment.


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 local distribution company businesses. The transaction is expected to close in the first quarter of 2025. For further information, see Note 21 to the consolidated financial statements.

(2) Summary of Significant Accounting Policies


(a)Use of Estimates

(a)Principles of Consolidation

The accompanying consolidated financial statements have been prepared in conformity with generally accepted accounting principles. The accounts of the Registrants and their wholly-owned and majority-owned and controlled subsidiaries are included in the consolidated financial statements. All intercompany transactions and balances are eliminated in consolidation, except as described below.

As of December 31, 2023, CenterPoint Energy, Houston Electric and SIGECO had VIEs including the Bond Companies and the SIGECO Securitization Subsidiary, which are consolidated. The consolidated VIEs are wholly-owned, bankruptcy-
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remote, special purpose entities that were formed solely for the purpose of securitizing transition property or facilitating the securitization financing of qualified costs in the second quarter of 2023 associated with the completed retirement of SIGECO’s A.B. Brown coal generation facilities. CenterPoint Energy, through SIGECO, has a controlling financial interest in the SIGECO Securitization Subsidiary and is the VIE’s primary beneficiary. For further information, see Note 7. Creditors of CenterPoint Energy, Houston Electric and SIGECO have no recourse to any assets or revenues of the Bond Companies or the SIGECO Securitization Subsidiary, as applicable. The Securitization Bonds issued by these VIEs are payable only from and secured by transition or securitization property, as applicable, and the bondholders have no recourse to the general credit of CenterPoint Energy, Houston Electric or SIGECO.

(b)Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

(b)Principles of Consolidation


The accounts of CenterPoint Energy(c)Equity Method and its wholly-owned and majority owned subsidiaries are included in the consolidated financial statements. All intercompany transactions and balances are eliminated in consolidation.Investments without a Readily Determinable Fair Value (CenterPoint Energy)

As of December 31, 2017, CenterPoint Energy had VIEs consisting of the Bond Companies, which it consolidates. The consolidated VIEs are wholly-owned, bankruptcy remote special purpose entities that were formed solely for the purpose of securitizing transition and system restoration related property. Creditors of CenterPoint Energy have no recourse to any assets or revenues of the Bond Companies. The bonds issued by these VIEs are payable only from and secured by transition and system restoration property and the bondholders have no recourse to the general credit of CenterPoint Energy.

(c)Equity and Cost Method Investments
CenterPoint Energy generally uses the equity method of accounting for investments in entities in which CenterPoint Energy has an ownership interest between 20% and 50% and exercises significant influence. CenterPoint Energy also uses the equity method for investments in which it has ownership percentages greater than 50%,entities when it exercises significant influence, does not have control and is not considered the primary beneficiary, if applicable. Generally, equity investments in limited partnerships with interest greater than approximately 3-5% is accounted for under the equity method.

In 2013, CenterPoint Energy, OGE and affiliates of ArcLight, formed Enable as a private limited partnership. CenterPoint Energy has the ability to significantly influence the operating and financial policies of, but not solely control, Enable and, accordingly, recorded an equity method investment. The net assets contributed were deemed to be in-substance real estate and were therefore recorded at historical cost.




Under the equity method, CenterPoint Energy adjusts its investment in Enableinvestments each period for contributions made, distributions received, CenterPoint Energy’s sharerespective shares of Enable’s comprehensive income and amortization of basis differences, as appropriate. CenterPoint Energy evaluates its equity method investments for impairment when events or changes in circumstances indicate there is a loss in value of the investment that is other than a temporary decline.

CenterPoint Energy’s investment in Enable is considered to be a VIE because the power to direct the activities that most significantly impact Enable’s economic performance does not reside with the holders of equity investment at risk. However, CenterPoint Energy is not considered the primary beneficiary of Enable since it does not have the power to direct the activities of Enable that are considered most significant to the economic performance of Enable.


CenterPoint Energy considers distributions received from equity method investments which do not exceed cumulative equity in earnings subsequent to the date of investment to be a return on investment and classifies these distributions as operating activities in theits Statements of Consolidated Cash Flows. CenterPoint Energy considers distributions received from equity method investments in excess of cumulative equity in earnings subsequent to the date of investment to be a return of investment and classifies these distributions as investing activities in theits Statements of Consolidated Cash Flows.


Other investments, excluding marketable securities, are carriedInvestments without a readily determinable fair value will be measured at cost.cost, less impairment, plus or minus observable prices changes of an identical or similar investment of the same issuer.

(d)Revenues


CenterPoint Energy records(d)Revenues

The Registrants record revenue for electricity delivery and natural gas sales and services under the accrual method and these revenues are recognized upon delivery to customers. Electricity deliveries not billed by month-end are accrued based on actual AMS meter data, daily supply volumes, estimated line loss and applicable tariff rates. Natural gas sales not billed by month-end are accrued based upon estimated purchased gas volumes, estimated lost and unaccounted for gas and currently effective tariff rates. For further discussion, see Note 5.


(e) MISO Transactions

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

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(f) Guarantees

CenterPoint Energy recognizes guarantee obligations at fair value. CenterPoint Energy discloses parent company guarantees of a subsidiary’s obligation when that guarantee results in the exposure of a material obligation of the parent company even if the probability of fulfilling such obligation is considered remote. See Note 15(c).  

(g) Long-lived Assets, Goodwill and Intangibles


CenterPoint Energy recordsThe Registrants record property, plant and equipment at historical cost. CenterPoint Energy expensescost and expense repair and maintenance costs as incurred.


CenterPoint EnergyThe Registrants periodically evaluatesevaluate long-lived assets, including property, plant and equipment, and specifically identifiable intangibles subject to amortization, when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable. The determinationFor rate-regulated businesses, recoverability of whether an impairment has occurredlong-lived assets is assessed by determining if a capital disallowance from a regulator is probable through monitoring the outcome of rate cases and other proceedings. For businesses that are not rate-regulated, recoverability is assessed based on an estimate of undiscounted cash flows attributable to the assets compared to the carrying value of the assets. No long-lived asset or intangible asset impairments were recorded in 2023, 2022 or 2021.


(f)CenterPoint Energy and CERC perform goodwill impairment tests at least annually and evaluate goodwill when events or changes in circumstances indicate that its carrying value may not be recoverable. CenterPoint Energy and CERC recognize a goodwill impairment by the amount a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill within that reporting unit. CenterPoint Energy includes deferred tax assets and liabilities within its reporting unit’s carrying value for the purposes of annual and interim impairment tests, regardless of whether the estimated fair value reflects the disposition of such assets and liabilities. For further information about the goodwill impairment tests, see Note 6.

(h) Assets Held for Sale and Discontinued Operations

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 the 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. A disposal group that meets the held for sale criteria and also represents a strategic shift to the Registrant is also reflected as discontinued operations on the Statements of Consolidated Income, and prior periods are recast to reflect the earnings or losses from such businesses as income from discontinued operations, net of tax.

(i) Regulatory Assets and Liabilities


CenterPoint Energy appliesThe Registrants apply the guidance for accounting for regulated operations towithin the Electric Transmission & Distribution businessreportable segment and the Natural Gas Distribution businessreportable segment. CenterPoint Energy’sThe Registrants’ rate-regulated subsidiaries may collect revenues subject to refund pending final determination in rate proceedings. In connection with such revenues, estimated rate refund liabilities are recorded which reflect management’s current judgment of the ultimate outcomes of the proceedings.


CenterPoint Energy’sThe Registrants’ rate-regulated businesses recognize removal costs as a component of depreciation expense in accordance with regulatory treatment. In addition, a portion of the amount of removal costs collected from customers that relate to AROs has been reclassified from a regulatory liability toreflected as an asset retirement liability in accordance with accounting guidance for AROs.


For further detail on CenterPoint Energy’sthe Registrants’ regulatory assets and liabilities, please see Note 6.7.


(g)(j) Depreciation and Amortization Expense


DepreciationThe Registrants compute depreciation and amortization is computed using the straight-line method based on economic lives or regulatory-mandated recovery periods. Amortization expense includes amortization of certain regulatory assets and other intangibles.


(h)
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(k) Capitalization and Deferral of Interest, including AFUDC

The Registrants capitalize interest and AFUDC

Interest and AFUDC are capitalized as a component of projects under construction and are amortizedamortize it over the assets’ estimated useful lives once the assets are placed in service. Additionally, the Registrants defer interest costs into a regulatory asset when amounts are probable of recovery. Deferred debt interest is amortized over the recovery period for rate-making purposes. AFUDC represents the composite interest cost of borrowed funds and a reasonable return on the equity funds used for construction for subsidiaries that apply the guidance for accounting for regulated operations. Although AFUDC increases both utilityproperty, plant and equipment and earnings, it is realized in cash when the assets are included in rates. The table below includes interest capitalized or deferred during the periods.

 Year Ended December 31,
 202320222021
 CenterPoint EnergyHouston ElectricCERCCenterPoint EnergyHouston ElectricCERCCenterPoint EnergyHouston ElectricCERC
 (in millions)
Capitalized interest and AFUDC debt (1)
$32 $18 $6 $26 $14 $7 $18 $13 $3 
AFUDC equity (2)
62 32 14 37 24 5 28 20 5 
Deferred debt interest (3)
65 16 43 51 12 36 26 1 22 


CenterPoint Energy recorded(1)Included in Interest expense and other finance charges on the following:Registrants’ respective Statements of Consolidated Income.
(2)Included in Other Income (Expense) on the Registrants’ respective Statements of Consolidated Income.
  Year Ended December 31,
  2017 2016 2015
  (in millions)
Capitalized interest and AFUDC included in Interest and other finance charges $9
 $8
 $10
AFUDC equity included in Other Income 11
 7
 12
(3)Represents the amount of deferred debt interest on certain regulatory assets that are authorized to earn a return, such as debt post in-service carrying costs on property, plant and equipment, gas costs, storm restoration costs, and TEEEF (including returns on both regulatory and lease assets).


(i)(l) Income Taxes


Houston Electric and CERC are included in CenterPoint Energy usesEnergy’s U.S. federal consolidated income tax return. Houston Electric and CERC report their income tax provision on a separate entity basis pursuant to a tax sharing policy with CenterPoint Energy. Current federal and certain state income taxes are payable to or receivable from CenterPoint Energy.

The Registrants use the asset and liability method of accounting for deferred income taxes. Deferred income tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases.basis. A valuation allowance is established against deferred tax assets for which management believes realization is not considered to be more likely than not. CenterPoint Energy recognizesThe Registrants recognize interest and penalties as a component of income tax expense.expense (benefit), as applicable, in their respective Statements of Consolidated Income. CenterPoint Energy reports the income tax provision associated with its interest in Enable in Incomediscontinued operations, net of tax expense (benefit) in its Statements of Consolidated Income. For further information, see Note 4.


To the extent certain EDIT of CenterPoint Energy’sthe Registrants’ rate-regulated subsidiaries may be recoverable or payable through future rates, regulatory assets and liabilities have been recorded, respectively.

On December 22, 2017, President Trump signed into law comprehensive tax reform legislation informally called the Tax Cuts and Jobs Acts, or TCJA, which resulted in significant changes to federal tax laws effective January 1, 2018. See Note 14 for further discussiondiscussion.

The Registrants use the portfolio approach to recognize income tax effects on other comprehensive income from accumulated other comprehensive income.

Investment tax credits are deferred and amortized to income over the approximate lives of the impacts ofrelated property. Production tax reform implementation.credits extended by the IRA may be used to reduce current federal income taxes payable.


(j)(m) Accounts Receivable and Allowance for Doubtful AccountsCredit Losses


Accounts receivable are recorded at the invoiced amount and do not bear interest. It is the policy of managementManagement reviews historical write-offs, current available information, and reasonable and supportable forecasts to review the outstanding accounts receivable monthly, as well as the bad debt write-offs experienced in the past,estimate and establish an allowance for doubtful accounts.credit losses. Account balances are charged off against the allowance when management determines it is probable the receivable will not be recovered. The provisionSee Note 7 for doubtful accounts in CenterPoint Energy’s Statementsfurther information about regulatory deferrals of Consolidated Income for 2017, 2016bad debt expense, including those related to COVID-19 and 2015 was $14 million, $7 million and $19 million, respectively.the February 2021 Winter Storm Event.


(k)
110

(n) Inventory


InventoryThe Registrants’ inventory consists principally of materials and supplies, and for CERC, natural gas.gas, and for CenterPoint Energy, coal inventory. Materials and supplies are valued at the lower of average cost or market. Materials and supplies are recorded to inventory when purchased and subsequently charged to expense or capitalized to plant when installed. Natural gas inventories ofInventory related to CenterPoint Energy’s Energy Services business segment areregulated operations is valued at historical cost consistent with ratemaking treatment. Coal inventory is valued at average cost. Certain natural gas in storage at CenterPoint Energy’s and CERC’s utilities are recorded using the lower ofLIFO method. CenterPoint Energy’s and CERC’s balances in inventory that were valued using LIFO method were as follows:

Year Ended December 31,
2023 (1)
2022
2023 (1)
2022
CenterPoint EnergyCERC
(in millions)
LIFO inventory$106 $101 $86 $82 

(1)Based on the average cost or market. Naturalof gas inventories ofpurchased during December 2023, CenterPoint Energy’s Natural Gas Distribution business segment are primarily valuedand CERC’s cost of replacing inventories carried at weighted average cost. During 2017, 2016LIFO cost was more than the carrying value at December 31, 2023 by $8 million and 2015, CenterPoint Energy recorded write-downs of natural gas inventory to the lower of average cost or market which are disclosed on the Statements of Consolidated Cash Flows.$13 million, respectively.


(l)(o) Derivative Instruments


CenterPoint Energy isThe Registrants are exposed to various market risks. These risks arise from transactions entered into in the normal course of business. CenterPoint Energy utilizesThe Registrants, from time to time, utilize derivative instruments such as physical forward contracts, swaps and options to mitigate the impact of changes in commodity prices, weather and interest rates on its operating results and cash flows. Such derivatives are recognized in CenterPoint Energy’sthe Registrants’ Consolidated Balance Sheets at their fair value unless CenterPoint Energythe Registrant elects the normal purchase and sales exemption for qualified physical transactions. A derivative may be designated as a normal purchase or normal sale if the intent is to physically receive or deliver the product for use or sale in the normal course of business.

CenterPoint Energy has a Risk Oversight Committee composedelected to record changes in the fair value of corporateamounts excluded from the assessment of effectiveness immediately in its Statements of Consolidated Income, and business segment officers that oversees commodity price, weather and credit risk activities, including CenterPoint Energy’s marketing, risk management services and hedging activities. The committee’s duties are to establish CenterPoint Energy’s commodity risk policies, allocate board-approved commercial risk limits, approve the use of new products and commodities, monitor positions and ensure compliance with CenterPoint Energy’s risk management policies and procedures and limits established by CenterPoint Energy’s Board of Directors.



CenterPoint Energy’s policies prohibit the use of leveraged financial instruments. A leveraged financial instrument, for this purpose, is a transaction involving a derivative whose financial impactsuch amounts will be based on an amount other than the notional amountcaptured in a regulatory asset or volume of the instrument.regulatory liability if they are recoverable or refundable to customers.


(m)(p) Investments in Other Debt and Equity Securities (CenterPoint Energy)


CenterPoint Energy reports equity securities classified as trading at estimated fair value in itsthe Consolidated Balance Sheets, and any unrealized holding gains and losses, net of any transaction costs, are recorded as Other Income (Expense)Gain (Loss) on Equity Securities in itsthe Statements of Consolidated Income.


(n)(q) Environmental Costs


CenterPoint Energy expensesThe Registrants expense or capitalizescapitalize environmental expenditures, as appropriate, depending on their future economic benefit. CenterPoint Energy expensesThe Registrants expense amounts that relate to an existing condition caused by past operations that do not have future economic benefit. CenterPoint Energy recordsThe Registrants record undiscounted liabilities related to these future costs when environmental assessments and/or remediation activities are probable and the costs can be reasonably estimated.


(o)(r) Cash and Cash Equivalents and Restricted Cash


For purposes of reporting cash flows, CenterPoint Energy considersthe Registrants consider cash equivalents to be short-term, highly-liquid investments with maturities of three months or less from the date of purchase. Cash and cash equivalents held by the Bond Companies and the SIGECO Securitization Subsidiary (VIEs) solely to support servicing the Securitization Bonds as of December 31, 20172023 and 20162022 are reflected on theCenterPoint Energy’s and Houston Electric’s Consolidated Balance Sheets.


In connection with the issuance of Securitization Bonds, CenterPoint Energy wasand Houston Electric were required to establish restricted cash accounts to collateralize the bonds that were issued in these financing transactions. These restricted cash accounts are not available for withdrawal until the maturity of the bonds and are not included in cash and cash equivalents. RestrictedFor more information on restricted cash accounts assee Note 18.

111

(s) Preferred Stock and Dividends

Preferred stock is evaluated to determine balance sheet classification, and all conversion and redemption features are evaluated for bifurcation treatment. Proceeds received net of December 31, 2017issuance costs are recognized on the settlement date. Cash dividends become a liability once declared. Income available to common stockholders is computed by deducting from net income the dividends accumulated and 2016 are reported below.earned during the period on cumulative preferred stock.

  December 31,
  2017 2016
  (in millions)
Restricted cash included in Prepaid expenses and other current assets $35
 $40
Restricted cash included in Other assets 1
 —
  Total restricted cash $36
 $40

(p)(t) New Accounting Pronouncements


Recently Adopted

In March 2016,November 2023, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation2023-07, Segment Reporting (Topic 718)280): Improvements to Employee Share-Based Payment Accounting (Reportable Segment Disclosures (“ASU 2016-09)2023-07”). The new guidance simplifies several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. CenterPoint Energy adopted this standard as of January 1, 2017. The adoption did not have a material impact on CenterPoint Energy’s financial position or results of operations.  However, CenterPoint Energy’s statement of cash flows reflects a decrease in financing activity and a corresponding increase in operating activity of $4 million, $3 million and $5 million as of December 31, 2017, 2016 and 2015, respectively, due to the retrospective application of the requirement that cash paid to a tax authority when shares are withheld to satisfy statutory income tax withholding obligations should be presented as a financing rather than as an operating activity.

Issued, Not Yet Effective

In January 2016, the FASB issuedThis ASU No. 2016-01, Financial Instruments-Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities (ASU 2016-01). ASU 2016-01 requires equity investments that do not result in consolidation and are not accounted for under the equity method to be measured at fair value and to recognize any changes in fair value in net income unless the investments qualify for the new practicability exception. It does not change the guidance for classifying and measuring investments in debt securities and loans. ASU 2016-01 also changes certainupdates segment disclosure requirements and other aspects related to recognition and measurement of financial assets and financial liabilities.through enhanced disclosures around significant segment expenses. ASU 2016-012023-07 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2017. As of the first reporting period in which


the guidance is adopted, a cumulative-effect adjustment to beginning retained earnings will be made, with two features that will be adopted prospectively. This standard will not have a material impact on CenterPoint Energy’s financial position, results of operations, cash flows and disclosures upon adoption on January 1, 2018.

In 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02) and related amendments. ASU 2016-02 provides a comprehensive new lease model that requires lessees to recognize assets and liabilities for most leases and would change certain aspects of lessor accounting. ASU 2016-02 is effective for fiscal years, and interim periods within those fiscal years beginning after December 15, 2018, with early adoption permitted. CenterPoint Energy expects to adopt this standard on January 1, 20192023, and is evaluating available transitional practical expedients. A modified retrospective adoption approach is required. CenterPoint Energy is in the process of reviewing contracts to identify leases as defined in ASU 2016-02 and expects to recognize on the statements of financial position right-of-use assets and lease liabilities for the majority of its leases that are currently classified as operating leases. CenterPoint Energy is continuing to assess the impact that this standard will have on its financial position, results of operations, cash flows and disclosures.

In 2016 and 2017, the FASB issued ASUs which amended ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606). ASU 2014-09, as amended, provides a comprehensive new revenue recognition model that requires revenue to be recognized in a manner that depicts the transfer of goods or services to a customer at an amount that reflects the consideration expected to be received in exchange for those goods or services. Early adoption is permitted, and entities have the option of using either a full retrospective or a modified retrospective adoption approach. While these ASUs will expand disclosures, CenterPoint Energy has not identified any significant changes as the result of these new standards. A substantial amount of CenterPoint Energy’s revenues are tariff and derivative based, which will not be significantly impacted by these ASUs. ASU 2014-09 eliminates industry specific guidance, including ASC 360-20, and as a result our investment in Enable will no longer be considered in-substance real estate. Gains or losses on subsequent sales or dilution events in our investment in Enable will be recognized in earnings. CenterPoint Energy adopted these ASUs on January 1, 2018 using the modified retrospective adoption approach.

In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (ASU 2016-15). ASU 2016-15 provides clarifying guidance on the classification of certain cash receipts and payments in the statement of cash flows and eliminates the variation in practice related to such classifications. ASU 2016-15 is effective for fiscal years, and interim periods within those fiscal years beginning after December 15, 2017, with early2024. Early adoption is permitted. CenterPoint Energy adoptedThe Registrants are currently evaluating the impact of this standardASU on January 1, 2018. A retrospective adoption approach is required. CenterPoint Energy does not believe this standard will have a material impact on itstheir respective consolidated financial position, results of operations, and disclosures. Due to the requirement that cash proceeds from COLI policies be classified as cash inflows from investing activity, there will be an increase in investing activity and a corresponding decrease in operating activity on the statement of cash flows when COLI proceeds are received.statements.


In November 2016,December 2023, the FASB issued ASU No. 2016-18, Statement2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures (“ASU 2023-09”). This ASU enhances the transparency of Cash Flows (Topic 230): Restricted Cash (income tax disclosures related to rate reconciliation and income taxes. ASU 2016-18). ASU 2016-18 requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, restricted cash and restricted cash equivalents. As a result, the statement of cash flows will no longer present transfers between cash and cash equivalents and restricted cash and restricted cash equivalents. When cash, cash equivalents, restricted cash and restricted cash equivalents are presented in more than one line item on the balance sheet, the new guidance requires a reconciliation of the totals in the statement of cash flows to the related captions in the balance sheet. ASU 2016-182023-09 is effective for fiscal years, and interimannual periods within those fiscal years, beginning after December 15, 2017, with early2024. Early adoption is permitted. A retrospective adoption approach is required. This standard will not have anThe Registrants are currently evaluating the impact on CenterPoint Energy’s financial position, results of operations, and disclosures, but it will have an impact on the presentation of the statement of cash flows upon adoption on January 1, 2018.

In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business (ASU 2017-01). ASU 2017-01 revises the definition of a business. If substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or a group of similar identifiable assets, then under ASU 2017-01, the asset or group of assets is not a business. The guidance also requires a business to include at least one substantive process and narrows the definition of outputs to be more closely aligned with how outputs are described in ASC 606. ASU 2017-01 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017, with early adoption permitted in certain circumstances. A prospective adoption approach is required. ASU 2017-01 could have a potential impact on CenterPoint Energy’s accounting for future acquisitions upon adoption on January 1, 2018.

In January 2017, the FASB issued ASU No. 2017-04, Intangibles-Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment (ASU 2017-04). ASU 2017-04 eliminates Step 2 of the goodwill impairment test, which requires a hypothetical purchase price allocation. A goodwill impairment will now be the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill. ASU 2017-04 is effective for fiscal years, and interim periods


within those fiscal years, beginning after December 15, 2019, with early adoption permitted. CenterPoint Energy will adopt ASU 2017-04 on January 1, 2018. A prospective adoption approach is required. ASU 2017-04 will have an impact on CenterPoint Energy’s future calculation of goodwill impairments if an impairment is identified.

In February 2017, the FASB issued ASU No. 2017-05, Other Income-Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20): Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets (ASU 2017-05). ASU 2017-05 clarifies when and how to apply ASC 610-20 Gains and Losses from the Derecognition of Nonfinancial Assets, which was issued as part of ASU 2014-09 Revenue from Contracts with Customers (Topic 606). ASU 2017-05 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017, with early adoption permitted. Companies can elect a retrospective or modified retrospective approach to adoption. This standard will not have a material impact on CenterPoint Energy’s financial position, results of operations, cash flows and disclosures upon adoption on January 1, 2018.

In March 2017, the FASB issued ASU No. 2017-07, Compensation-Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires an employer to report the service cost component of the net periodic pension cost and postretirement benefit cost in the same line item(s) as other employee compensation costs arising from services rendered during the period; all other components will be presented separately from the line item(s) that includes the service cost and outside of any subtotal of operating income. In addition, only the service cost component will be eligible for capitalization in assets. ASU 2017-07 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017, with early adoption permitted. ASU 2017-07 should be applied retrospectively for the presentation of the service cost component and the other components and prospectively for the capitalization of the service cost component. The adoption of this guidance is expected to result in an increase to operating income and a decrease to other income. Prospectively, other components previously capitalized in assets will be recorded as regulatory assets in CenterPoint Energy’s rate-regulated businesses. This standard will not have a material impactASU on CenterPoint Energy’stheir respective consolidated financial position, results of operations, cash flows and disclosures upon adoption on January 1, 2018.statements.

In May 2017, the FASB issued ASU No. 2017-09, Compensation-Stock Compensation (Topic 718): Scope of Modification Accounting (ASU 2017-09). ASU 2017-09 clarifies when changes to the terms or conditions of a share-based payment award must be accounted for as a modification. Entities will apply the modification accounting guidance if the value, vesting conditions or classification of the award changes. ASU 2017-09 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017, with early adoption permitted. ASU 2017-09 should be applied prospectively for awards modified on or after the adoption date. This standard, upon adoption on January 1, 2018, will have an impact on CenterPoint Energy’s accounting for future changes to share-based payment awards.

In August 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12). ASU 2017-12 expands an entity’s ability to hedge nonfinancial and financial risk components and reduce complexity in fair value hedges of interest rate risk. The guidance eliminates the requirement to separately measure and report hedge ineffectiveness, eases certain documentation and assessment requirements, and updates the presentation and disclosure requirements. ASU 2017-12 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted. A cumulative-effect adjustment to eliminate the separate measurement of ineffectiveness upon adoption is required for existing cash flow and net investment hedges. Presentation and disclosure guidance should be applied prospectively. CenterPoint Energy is currently assessing the impact that this standard will have on its financial position, results of operations, cash flows and disclosures.


Management believes that all other recently adopted and recently issued accounting standards whichthat are not yet effective will not have a material impact on CenterPoint Energy’s consolidatedthe Registrants’ financial position, results of operations or cash flows upon adoption.




(3) Property, Plant and Equipment


(a) Property, Plant and Equipment


Property, plant and equipment includes the following:
December 31, 2023December 31, 2022
Weighted Average Useful LivesProperty, Plant and Equipment, GrossAccumulated Depreciation & AmortizationProperty, Plant and Equipment, NetProperty, Plant and Equipment, GrossAccumulated Depreciation & AmortizationProperty, Plant and Equipment, Net
(in years)(in millions)
CenterPoint Energy
Electric transmission and distribution37$19,151 $4,762 $14,389 $19,154 $5,317 $13,837 
Electric generation (1)251,381 315 1,066 2,120 813 1,307 
Natural gas distribution3216,492 4,337 12,155 15,097 4,135 10,962 
Finance ROU asset mobile generation7.5662 136 526 662 41 621 
Other property222,710 993 1,717 695 279 416 
Total$40,396 $10,543 $29,853 $37,728 $10,585 $27,143 
Houston Electric
Electric transmission and distribution37$16,800 $3,641 $13,159 $14,791 $3,556 $11,235 
Finance ROU asset mobile generation7.5662 136 526 662 41 621 
Other property202,053 692 1,361 2,300 695 1,605 
Total$19,515 $4,469 $15,046 $17,753 $4,292 $13,461 
CERC
Natural gas distribution31$15,591 $4,136 $11,455 $14,316 $3,946 $10,370 
Other property1581 33 48 63 27 36 
Total$15,672 $4,169 $11,503 $14,379 $3,973 $10,406 

(1)SIGECO and AGC own a 300 MW unit at the Warrick Power Plant (Warrick Unit 4) as tenants in common as of December 31, 2023. SIGECO’s share of the cost of this unit as of December 31, 2023, is $198 million with accumulated depreciation totaling $171 million. Under the operating agreement, AGC and SIGECO shared equally in the cost of operation and output of the unit. SIGECO’s share of operating costs is included in Operation and maintenance expense in CenterPoint Energy’s Statements of Consolidated Income. SIGECO exited joint operations of Warrick 4 on January 1, 2024.

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Weighted Average
Useful Lives
 December 31,
 (in years) 2017 2016
   (in millions)
Electric Transmission & Distribution32 $11,496
 $10,840
Natural Gas Distribution28 6,735
 6,219
Energy Services27 102
 83
Other property26 698
 689
Total  19,031
 17,831
Accumulated depreciation and amortization:     
Electric Transmission & Distribution  3,633
 3,443
Natural Gas Distribution  1,968
 1,722
Energy Services  35
 29
Other property  338
 330
Total accumulated depreciation and amortization  5,974
 5,524
Property, plant and equipment, net  $13,057
 $12,307


(b) Depreciation and Amortization


The following table presents depreciation and amortization expense for 2017, 20162023, 2022 and 2015.2021:
 Year Ended December 31,
 202320222021
 CenterPoint EnergyHouston ElectricCERCCenterPoint EnergyHouston ElectricCERCCenterPoint EnergyHouston ElectricCERC
 (in millions)
Depreciation$1,092 $484 $459 $1,013 $434 $420 $1,024 $391 $466 
Amortization of securitized regulatory assets163 155 — 191 191 — 213 213 — 
Other amortization146 109 34 84 45 28 79 38 17 
Total$1,401 $748 $493 $1,288 $670 $448 $1,316 $642 $483 
 2017 2016 2015
 (in millions)
Depreciation expense$619
 $607
 $557
Amortization expense417
 519
 413
Total depreciation and amortization expense$1,036
 $1,126
 $970


(c) AROs


A reconciliationThe Registrants account for an ARO at fair value in the period during which the legal obligation is incurred if a reasonable estimate of fair value and its settlement date can be made. At the timing of recording an ARO, the associated asset retirement costs are capitalized as part of the changes incarrying amount of the AROrelated long-lived asset. The Registrants recognize a regulatory asset or liability is as follows:for the timing differences between the recognition of expenses and costs recovered through the ratemaking process. The estimates of future liabilities are developed using a discounted cash flow model based upon estimates and assumptions of future costs, interest rates, credit-adjusted risk-free rates and the estimated timing of settlement.

 December 31,
 2017 2016
 (in millions)
Beginning balance$205
 $195
Accretion expense8
 10
Revisions in estimates of cash flows68
 —
Ending balance$281
 $205

CenterPoint EnergyThe Registrants have recorded AROs associated with the removal of asbestos and asbestos-containing material in its buildings, including substation building structures. CenterPoint Energy recorded AROs relating to the closure of the ash ponds at A.B. Brown and F.B. Culley. CenterPoint Energy and Houston Electric also recorded AROs relating to gas pipelines abandoned in place, treated wood poles for electric distribution, distribution transformers containing PCB (also known as Polychlorinated Biphenyl), and underground fuel storage tanks. The estimatesCenterPoint Energy and CERC also recorded AROs relating to gas pipelines abandoned in place.

A reconciliation of future liabilities were developed using historical information, and where available, quoted prices from outside contractors.

The increase of $68 millionthe changes in the ARO fromliability recorded in Other non-current liabilities on each of the revisionRegistrants’ respective Consolidated Balance Sheets is as follows:
 December 31, 2023December 31, 2022
 CenterPoint EnergyHouston ElectricCERCCenterPoint EnergyHouston ElectricCERC
 (in millions)
Beginning balance$610 $36 $420 $659 $42 $479 
Accretion expense (1)
23 1 16 20 1 15 
Revisions in estimates (2)
(43)3 (56)(69)(7)(74)
Ending balance$590 $40 $380 $610 $36 $420 

(1)Reflected in estimatesRegulatory assets on each of the Registrants’ respective Consolidated Balance Sheets.
(2)In 2023 and 2022, CenterPoint Energy and CERC reflected a decrease in 2017 istheir respective ARO liability, which was primarily attributable to increases in the long-term interest rates used for discounting in the ARO calculation. In 2023, Houston Electric reflected an increase in its ARO liability attributable to an increase in discount rates and disposal costs, while in 2022, Houston Electric reflected a decrease in its ARO liability, which was primarily attributable to increases in the long-term discountsinterest rates used for discounting in the ARO calculation for CERC.calculation.




(4) AcquisitionDivestitures (CenterPoint Energy and CERC)


Divestiture of Energy Systems Group. On January 3, 2017,CES, an indirect, wholly-owned subsidiary ofMay 21, 2023, CenterPoint Energy, completedthrough its acquisitionsubsidiary Vectren Energy Services, entered into an Equity Purchase Agreement to sell all of AEM. Afterthe outstanding limited liability company interests of Energy Systems Group to ESG Holdings Group, for a purchase price of $157 million, subject to customary adjustments set forth in the Equity Purchase Agreement, including adjustments based on Energy Systems Group’s net working capital at closing, indebtedness, cash and cash equivalents and transaction expenses. The transaction closed on June 30, 2023, and CenterPoint Energy received $154 million in cash. Additionally, as of December 31, 2023, CenterPoint Energy had a payable of
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approximately $2 million to ESG Holdings Group for working capital and other adjustments set forth in the final purchase price was $147 million and was allocated to identifiableEquity Purchase Agreement.

In May 2023, certain assets acquired and liabilities assumed basedof Energy Systems Group met the held for sale criteria. The divestiture of Energy Systems Group reflects CenterPoint Energy’s continued strategic focus on their estimated fair valuesits core utility businesses. The historical annual revenues, net income and total assets of Energy Systems Group did not have a sufficient effect, quantitatively or qualitatively, on CenterPoint Energy’s financial results to be considered a strategic shift. Therefore, the income and expenses associated with Energy Systems Group were not reflected as discontinued operations on CenterPoint Energy’s Statements of Consolidated Income. For disposal groups that are classified as held for sale but that do not meet the criteria for discontinued operations reporting, the assets and liabilities of the disposal group are required to be separately presented on the acquisition date.

The following table summarizesface of the final purchase price allocation andbalance sheet only in the fair value amounts recognizedinitial period in which it is classified as held for thesale. Therefore, CenterPoint Energy’s Consolidated Balance Sheets as of December 31, 2022 were not recast to reflect Energy Systems Group’s assets acquired and liabilities assumedas held for sale. Depreciation and amortization of long-lived assets ceased at the end of the quarter in which the held for sale criteria is met. Additionally, as a result of the completion of the sale of Energy Systems Group in June 2023, there were no assets or liabilities classified as held for sale as of December 31, 2023. For a discussion of guarantees and product warranties related to Energy Systems Group, see Note 15(c).

CenterPoint Energy recognized a loss on sale of approximately $13 million, including $3 million of transaction costs, during the acquisition:

  (in millions)
Total purchase price consideration $147
Cash $15
Receivables 140
Natural gas inventory 78
Derivative assets 35
Prepaid expenses and other current assets 5
Property and equipment 8
Identifiable intangibles 25
Total assets acquired 306
Accounts payable 113
Derivative liabilities 43
Other current liabilities 7
Other liabilities 1
Total liabilities assumed 164
Identifiable net assets acquired 142
Goodwill 5
Net assets acquired $147


The goodwill of $5 million resulting from the acquisition reflects the excess of the purchase price over the fair value of the net identifiable assets acquired. The goodwill recorded as part of the acquisition primarily reflects the value of the complementary operational and geographic footprints, scale and expanded capabilities provided by the acquisition.

Identifiable intangible assets were recorded at estimated fair value as determined by management based on available information, which included a valuation prepared by an independent third party. The significant assumptions used in arriving at the estimated identifiable intangible asset values included management’s estimates of future cash flows, the discount rate which is based on the weighted average cost of capital for comparable publicly traded guideline companies and projected customer attrition rates. The useful lives for the identifiable intangible assets were determined using methods that approximate the pattern of economic benefit provided by the utilization of the assets.

The estimated fair value of the identifiable intangible assets and related useful lives as included in the final purchase price allocation include:
  Estimate Fair Value Estimate Useful Life
  (in millions) (in years)
Customer relationships $25
 15

Amortization expense related to the above identifiable intangible assets was $2 million for the yeartwelve months ended December 31, 2017.2023, in connection with the closing of the sale of Energy Systems Group. Additionally, CenterPoint Energy recognized a current tax expense of $32 million during the twelve months ended December 31, 2023, as a result of the cash taxes payable upon the closing of the sale.


Revenues of approximately $1.3 billionThe pre-tax income (loss) for Energy Systems Group, excluding interest and operating income of approximately $74 million attributable to the AEM acquisition are reported in the Energy Services business segment andcorporate allocations, included in CenterPoint Energy’s Statements of Consolidated Income is as follows:

Year Ended December 31,
2023 (1)
20222021
(in millions)
Income (Loss) from Continuing Operations Before Income Taxes$(4)$2 $(3)

(1)Reflects January 1, 2023 to June 30, 2023 results only due to of the sale of Energy Systems Group.

Divestiture of Arkansas and Oklahoma Natural Gas Businesses (CenterPoint Energy and CERC).On April 29, 2021, CenterPoint Energy, through its subsidiary CERC Corp., entered into the AROK Asset Purchase Agreement to sell its Arkansas and Oklahoma Natural Gas businesses for $2.15 billion in cash, including recovery of approximately $425 million in natural gas costs, including storm-related incremental natural gas costs associated with the February 2021 Winter Storm Event, subject to certain adjustments set forth in the AROK Asset Purchase Agreement. The assets included approximately 17,000 miles of main pipeline in Arkansas, Oklahoma and certain portions of Bowie County, Texas serving more than half a million customers. The transaction closed on January 10, 2022.

The sale was considered an asset sale for tax purposes, requiring net deferred tax liabilities to be excluded from held for sale balances. The deferred taxes associated with the businesses were recognized as a deferred income tax benefit by CenterPoint Energy and CERC upon closing of the sale in 2022.

Although the Arkansas and Oklahoma Natural Gas businesses met the held for sale criteria as of December 31, 2021, their disposals did not represent a strategic shift to CenterPoint Energy and CERC, as both retained significant operations in, and continued to invest in, their natural gas businesses. Therefore, the income and expenses associated with the disposed businesses were not reflected as discontinued operations on CenterPoint Energy’s and CERC’s Statements of Consolidated Income, as applicable. Since the depreciation on the Arkansas and Oklahoma Natural Gas assets continued to be reflected in revenues through customer rates until the closing of the transaction and will be reflected in the carryover basis of the rate-regulated assets, CenterPoint Energy and CERC continued to record depreciation on those assets through the closing of the transaction. The Registrants record assets and liabilities held for sale at the lower of their carrying value or their estimated fair value less cost to sell.

CenterPoint Energy and CERC recognized gains of $303 million and $557 million, respectively, net of transaction costs of $59 million, in connection with the closing of the disposition of the Arkansas and Oklahoma Natural Gas businesses during the year ended December 31, 2017.2022. CenterPoint Energy and CERC collected a receivable of $15 million in May 2022 for full and final settlement of the working capital adjustment under the AROK Asset Purchase Agreement.

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Neither CenterPoint Energy nor CERC recognized any gains or losses on the measurement of assets held for sale during the year ended December 31, 2021. See Note 6 for further information about the allocation of goodwill to the businesses to be disposed.

As a result of the completion of the sale of the Arkansas and Oklahoma Natural Gas businesses, there were no assets or liabilities classified as held for sale as of December 31, 2022.

The pre-tax income for the Arkansas and Oklahoma Natural Gas businesses, excluding interest and corporate allocations, included in CenterPoint Energy’s and CERC’s Statements of Consolidated Income is as follows:
Year Ended December 31,Year Ended December 31,
2022 (1)
2021
(in millions)
Income from Continuing Operations Before Income Taxes$9 $78 

(1)Reflects January 1, 2022 to January 9, 2022 results only due to of the sale of the Arkansas and Oklahoma Natural Gas businesses.

Effective on the date of the closing of the disposition of the Arkansas and Oklahoma Natural Gas businesses, a subsidiary of CenterPoint Energy entered into the Transition Services Agreement, whereby that subsidiary agreed to provide certain transition services such as accounting, customer operations, procurement, and technology functions for a term of up to twelve months. In November 2022, a significant majority of all services under the Transition Services Agreement were terminated, and on January 10, 2023, all remaining services were terminated.

CenterPoint Energy’s charges to Southern Col Midco for reimbursement of transition services was less than $1 million and $40 million during the years ended December 31, 2023 and 2022, respectively. Actual transition services costs incurred are recorded net of amounts charged to Southern Col Midco. CenterPoint Energy had no accounts receivable and accounts receivable of $1 million as of December 31, 2023 and 2022, respectively, from Southern Col Midco for transition services.

Divestiture of MES (CenterPoint Energy and CERC). CenterPoint Energy, through its subsidiary CERC Corp., completed the sale of MES on August 31, 2021 to Last Mile Energy. Prior to the transaction, MES provided temporary delivery of LNG and CNG throughout the contiguous 48 states and MES was reflected in CenterPoint Energy’s Natural Gas reportable segment and CERC’s single reportable segment, as applicable.

The MES disposal did not represent a strategic shift to CenterPoint Energy and CERC, as both retained significant operations in, and continued to invest in, their natural gas businesses. Therefore, the income and expenses associated with MES are not reflected as discontinued operations on CenterPoint Energy’s and CERC’s Statements of Consolidated Income, as applicable. CenterPoint Energy and CERC recognized a pre-tax gain on the sale of $8 million and $11 million, respectively, during year ended December 31, 2021. See Note 6 for further information about the allocation of goodwill to the MES disposal.

Discontinued Operations (CenterPoint Energy)

CenterPoint Energy’s discontinued operations reflect the disposal of its interests in Enable, which represented a strategic shift that had a major effect on CenterPoint Energy’s operations and financial results. As such, the equity in earnings of unconsolidated affiliates, net of tax, associated with CenterPoint Energy’s equity investment in Enable was reflected as discontinued operations on CenterPoint Energy’s Statements of Consolidated Income.

A summary of discontinued operations presented in CenterPoint Energy’s Statements of Consolidated Income is as follows:
Year Ended December 31, 2021
(in millions)
Equity in earnings of unconsolidated affiliate, net$1,019 
Income from discontinued operations before income taxes1,019 
Income tax expense201 
Net income from discontinued operations$818 
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CenterPoint Energy elected not to separately disclose discontinued operations on its Statements of Consolidated Cash Flows. Except as discussed in Note 2, long-lived assets are not depreciated or amortized once they are classified as held for sale. The following table summarizes CenterPoint Energy’s cash flows from discontinued operations and certain supplemental cash flow disclosures as applicable:

Year Ended December 31, 2021
Cash flows from operating activities:(in millions)
Adjustments to reconcile net income to net cash provided by operating activities:
Gain on Enable Merger$(681)
Equity in earnings of unconsolidated affiliate(339)
Distributions from unconsolidated affiliate155 
Cash flows from investing activities:
Transaction costs related to the Enable Merger(49)
Cash received related to Enable Merger5 

Disposal of Investment in Enable (CenterPoint Energy).On December 2, 2021, Enable completed the previously announced Enable Merger pursuant to the Enable Merger Agreement entered into on February 16, 2021. At the closing of the Enable Merger on December 2, 2021, Energy Transfer acquired 100% of Enable’s outstanding common and preferred units, and, as a result, Enable Common Units owned by CenterPoint Energy were exchanged for Energy Transfer Common Units and Enable Series A Preferred Units owned by CenterPoint Energy were exchanged for Energy Transfer Series G Preferred Units.

During the year ended December 31, 2022, CenterPoint Energy sold all of its remaining Energy Transfer Common Units and Energy Transfer Series G Preferred Units. See Note 11 for further information regarding Energy Transfer equity securities.

Distributions Received from Enable (CenterPoint Energy):
Year Ended December 31, 2021
Per UnitCash Distribution
(in millions)
Enable Common Units$0.6610 $155 
Enable Series A Preferred Units2.2965 34 
Total$189 
Transactions with Enable (CenterPoint Energy and CERC):

The transactions with Enable through December 2, 2021 in the following tables exclude transactions with the Energy Services Disposal Group.
Year Ended December 31, 2021
(in millions)
Natural gas expenses, including transportation and storage costs (1)
$85 

(1)Included in Utility natural gas, fuel and purchased power on CenterPoint Energy’s Statements of Consolidated Income and in Utility natural gas on CERC’s Statements of Consolidated Income.
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Summarized Financial Information for Enable (CenterPoint Energy)

Summarized consolidated income (loss) information for Enable is as follows:
Year Ended December 31, 2021 (1)
(in millions)
Operating revenues$3,466 
Cost of sales, excluding depreciation and amortization1,959 
Depreciation and amortization382 
Operating income634 
Net income attributable to Enable Common Units461 
Reconciliation of Equity in Earnings (Losses), net before income taxes:
CenterPoint Energy’s interest$248 
Basis difference amortization (2)
92 
Loss on dilution, net of proportional basis difference recognition(1)
Gain on Enable Merger680 
CenterPoint Energy’s equity in earnings (losses), net before income taxes (3)
$1,019 
(1)Reflects January 1, 2021 to December 2, 2021 results only due to the closing of the Enable Merger.
(2)Equity in earnings of unconsolidated affiliate includes CenterPoint Energy’s share of Enable earnings adjusted for the amortization of the basis difference of CenterPoint Energy’s original investment in Enable and its underlying equity in net assets of Enable. The basis difference was being amortized through the year 2048 and ceased upon closing of the Enable Merger.
(3)Reported as discontinued operations on CenterPoint Energy’s Statements of Consolidated Income.

(5) Revenue Recognition

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

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

The following unaudited pro forma financial information reflectstables disaggregate revenues by reportable segment and major source:

CenterPoint Energy
Year Ended December 31, 2023
ElectricNatural GasCorporate and OtherTotal
(in millions)
Revenue from contracts with customers$4,275 $4,210 $127 $8,612 
Other (1)
15 69 3 87 
Eliminations— (3)— (3)
Total revenues$4,290 $4,276 $130 $8,696 
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Year Ended December 31, 2022
ElectricNatural GasCorporate and OtherTotal
(in millions)
Revenue from contracts with customers$4,095 $4,969 $263 $9,327 
Other (1)
13 (23)4 (6)
Total revenues$4,108 $4,946 $267 $9,321 
Year Ended December 31, 2021
ElectricNatural GasCorporate and OtherTotal
(in millions)
Revenue from contracts with customers$3,726 $4,281 $249 $8,256 
Other (1)
37 55 4 96 
Total revenues$3,763 $4,336 $253 $8,352 

(1)Primarily consists of income from ARPs and leases. Total lease income was $8 million, $7 million and $7 million for each of the consolidated resultsyears ended December 31, 2023, 2022 and 2021, respectively.

Houston Electric

Year Ended December 31,
202320222021
(in millions)
Revenue from contracts with customers$3,684 $3,417 $3,117 
Other (1)
(7)(5)17 
Total revenues$3,677 $3,412 $3,134 

(1)Primarily consists of operationsincome from ARPs and leases. Lease income was not significant for the years ended December 31, 2023, 2022, and 2021.

CERC
Year Ended December 31,
202320222021
(in millions)
Revenue from contracts with customers$4,083 $4,816 $4,148 
Other (1)
66 (16)52 
Total revenues$4,149 $4,800 $4,200 

(1)Primarily consists of income from ARPs and leases. Lease income was $4 million, $3 million and $3 million, respectively, for the years ended December 31, 2023, 2022 and 2021.

Revenues from Contracts with Customers

Electric (CenterPoint Energy and Houston Electric). Houston Electric distributes electricity to customers over time and customers consume the electricity when delivered. Indiana Electric generates, distributes and transmits electricity to customers over time, and customers consume the electricity when delivered. Revenue, consisting of both volumetric and fixed tariff rates set by state regulators, such as the PUCT and the IURC, is recognized as electricity is delivered and represents amounts both billed and unbilled. Discretionary services requested by customers are provided at a point in time with control transferring upon the completion of the service. Revenue for discretionary services provided by Houston Electric is recognized upon completion of service based on the tariff rates set by the PUCT. Payments for electricity distribution and discretionary services are aggregated and received on a monthly basis. Houston Electric performs transmission services over time as a stand-ready obligation to provide a reliable network of transmission systems. Revenue is recognized upon time elapsed, and the monthly tariff rate set by the regulator. Payments are received on a monthly basis. Indiana Electric customers are billed monthly and payment terms, set by the regulator, require payment within a month of billing.
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Natural Gas (CenterPoint Energy and CERC). CenterPoint Energy assumingand CERC distribute and transport natural gas to customers over time, and customers consume the AEM acquisition had taken placenatural gas when delivered. Revenue, consisting of both volumetric and fixed tariff rates set by the state governing agency for that service area, is recognized as natural gas is delivered and represents amounts both billed and unbilled. Discretionary services requested by the customer are provided at a point in time with control transferring upon completion of the service. Revenue for discretionary services is recognized upon completion of service based on January 1, 2016. Adjustmentsthe tariff rates set by the applicable state regulator. Payments of natural gas distribution, transportation and discretionary services are aggregated and received on a monthly basis.

Contract Balances. When the timing of delivery of service is different from the timing of the payments made by customers and when the right to pro forma net income include intercompany sales, amortizationconsideration is conditioned on something other than the passage of intangibletime, the Registrants recognize either a contract asset (performance precedes billing) or a contract liability (customer payment precedes performance). Those customers that prepay are represented by contract liabilities until the performance obligations are satisfied. The Registrants’ contract assets depreciationare included in Accrued unbilled revenues and contract liabilities are included in Accounts payable and Other current liabilities in their Consolidated Balance Sheets. CenterPoint Energy’s contract assets and contract liabilities primarily related to Energy Systems Group contracts where revenue was recognized using the input method prior to the sale of fixedEnergy Systems Group that was completed on June 30, 2023.

The opening and closing balances of accounts receivable, other accrued unbilled revenue, contract assets interest expense associatedand contract liabilities from contracts with debt financingcustomers are as follows:

CenterPoint Energy
Accounts ReceivableOther Accrued Unbilled Revenues
Contract
Assets (1)
Contract Liabilities (1)
(in millions)
Opening balance as of December 31, 2022$858 $764 $4 $45 
Closing balance as of December 31, 2023652 516 — 2 
Increase (decrease)$(206)$(248)$(4)$(43)

(1) Decrease primarily related to fund the acquisition, and related income tax effects. completed sale of Energy Systems Group on June 30, 2023.

The pro forma informationamount of revenue recognized in the year ended December 31, 2023 that was included in the opening contract liability was $2 million.

Houston Electric
Accounts ReceivableOther Accrued Unbilled RevenuesContract Liabilities
(in millions)
Opening balance as of December 31, 2022$271 $142 $2 
Closing balance as of December 31, 2023275 142 2 
Increase$4 $— $— 

The amount of revenue recognized in the year ended December 31, 2023 that was included in the opening contract liability was $2 million.

CERC
Accounts ReceivableOther Accrued
Unbilled Revenues
(in millions)
Opening balance as of December 31, 2022$478 $573 
Closing balance as of December 31, 2023330 329 
Decrease$(148)$(244)

CERC does not includehave any opening or closing contract asset or contract liability balances.
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Remaining Performance Obligations (CenterPoint Energy).Following the mark-to-market impactcompleted sale of financial instruments designated as cash flow hedges of anticipated purchasesEnergy Systems Group on June 30, 2023, CenterPoint Energy had no remaining performance obligations.

Practical Expedients and sales at index prices. The effective portion of these hedges isExemption. Sales taxes and other similar taxes collected from customers are excluded from earningsthe transaction price. For contracts for which revenue from the satisfaction of the performance obligations is recognized in the amount invoiced, the practical expedient was elected and reportedrevenue expected to be recognized on these contracts has not been disclosed.

Allowance for Credit Losses and Bad Debt Expense

CenterPoint Energy and CERC segregate financial assets that fall under the scope of Topic 326, primarily trade receivables due in one year or less, into portfolio segments based on shared risk characteristics, such as geographical location and regulatory environment, for evaluation of expected credit losses. Historical and current information, such as average write-offs, are applied to each portfolio segment to estimate the allowance for losses on uncollectible receivables. Additionally, the allowance for losses on uncollectible receivables is adjusted for reasonable and supportable forecasts of future economic conditions, which can include changing weather, commodity prices, regulations, and macroeconomic factors, among others. Houston Electric had no material changes in Other comprehensive income. Additionally,its methodology to recognize losses on financial assets that fall under the pro forma information does not includescope of Topic 326, primarily due to the mark-to-market impactnature of physical forward transactions that were previously accounted for as normal purchaseits customers and sale transactions.regulatory environment. For a discussion of regulatory deferrals, see Note 7.


The unaudited pro forma financial information has been presentedtable below summarizes the Registrants’ bad debt expense amounts for illustrative purposes only2023, 2022 and is not necessarily indicative2021, net of the consolidated results of operations that would have been achieved had the acquisition taken place on the dates indicated or the future consolidated results of operations of the combined company.regulatory deferrals, including those related to COVID-19:
 Year Ended December 31,
 202320222021
 CenterPoint EnergyHouston ElectricCERCCenterPoint EnergyHouston ElectricCERCCenterPoint EnergyHouston ElectricCERC
(in millions)
Bad debt expense$18 $— $16 $20 $— $17 $12 $— $10 
Bad debt expense deferred as regulatory asset— — — — — — 16 8 8 

  Year Ended December 31,
  2017 2016
  (in millions)
Operating Revenue $9,614
 $8,541
Net Income (1)
 1,792
 442

(1)Net income for the year ended December 31, 2017 includes a reduction in income taxes of $1,113 million due to tax reform. See Note 14 for further discussion of the impacts of tax reform implementation.

(5)(6) Goodwill and Other Intangibles (CenterPoint Energy and CERC)


Goodwill (CenterPoint Energy)

CenterPoint Energy’s goodwill by reportable business segment as of December 31, 2016 and changes in the carrying amount of goodwill as of December 31, 2017 areis as follows:

December 31, 2022DisposalsDecember 31, 2023
(in millions)
Electric (1)
$936 $— $936 
Natural Gas2,920 — 2,920 
Corporate and Other438 134 (2)304 
Total$4,294 $134 $4,160 

 December 31, 2016 AEM Acquisition (1) December 31,
2017		 
 (in millions) 
Natural Gas Distribution$746
 $—
 $746
 
Energy Services105
(2)5
 110
(2)
Other Operations11
 —
 11
 
Total$862
 $5
 $867
 
(1) See Note 4.
(2) Amount presented is net of the accumulated goodwill impairment charge of $252$185 million recorded in 2020.
(2)Represents goodwill attributable to the sale of Energy Systems Group. For further information, see Note 4.

CERC’s goodwill as of both December 31, 2023 and December 31, 2022 was $1,583 million.


When the net assets or equity interest transferred in a common-control transaction constitute a business, goodwill is included with the net assets transferred at the parent company’s historical basis. CenterPoint Energy applied a relative fair value methodology to determine the amount of goodwill to allocate to CERC from its natural gas reporting unit as part of the Restructuring.

When 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. As described further in Note 4, certain assets and liabilities of Energy Systems Group, including goodwill of $134 million at CenterPoint Energy, were disposed of upon consummation of the sale of Energy Systems
120

Group in the second quarter of 2023. The disposal of goodwill attributable to Energy Systems Group was reflected in the loss on sale of $13 million during the year ended December 31, 2023.

CenterPoint Energy performsand CERC perform goodwill impairment tests at least annually and evaluatesevaluate goodwill when events or changes in circumstances indicate that its carrying value may not be recoverable. The impairment evaluation for goodwill is performed by using a two-step process. In the first step,comparing the fair value of each reporting unit is compared with the carrying amount of the reporting unit, including goodwill. The reporting units approximate the reportable segments, with the exception of Energy Systems Group, which is a separate reporting unit but included in Corporate and Other at CenterPoint Energy. The estimated fair value of the reporting unit is generallyprimarily determined based on an income approach or a weighted combination of income and market approaches. If the basiscarrying amount is in excess of discounted cash flows. If the estimated fair value of the reporting unit, then the excess amount is less thanrecorded as an impairment charge, not to exceed the carrying amount of the reporting unit, then a second step must be completed to determine the amount of the goodwill impairment that should be recorded. In the second step, the implied fair value of the reporting unit’s goodwill is determined by allocating the reporting unit’s fair value to all of its assets and liabilities other than goodwill (including any unrecognized intangible assets) in a manner similar to a purchase price allocation. The resulting implied fair value of the goodwill that results from the application of this second step is then compared to the carrying amount of the goodwill and an impairment charge is recordedgoodwill. See Note 2(g) for the difference.further discussion.


CenterPoint Energy and CERC performed itsthe annual goodwill impairment testtests in the third quarter of each of 20172023 and 20162022 and determined based on the results of the first step, that no goodwill impairment charge was required for any reporting unit which approximate the reportable segments.as a result of those tests.



Other Intangibles (CenterPoint Energy)


The tables below present information on CenterPoint Energy’s other intangible assets, excluding goodwill, recorded in Other non-current assets on the Consolidated Balance Sheets.Sheets and the related amortization expense included in Depreciation and amortization on CenterPoint Energy’s Statements of Consolidated Income, unless otherwise indicated in the tables below. The intangible assets and associated amortization expense were primarily related to Energy Systems Group prior to the completion of the sale in June 2023 as indicated below. As a result, there are no intangible assets to report as of December 31, 2023. See Note 4 for further information.
December 31, 2022
Gross Carrying AmountAccumulated AmortizationNet Balance
(in millions)
Customer relationships (1)
$33 $(16)$17 
Trade names (1)
16 (6)10 
Operation and maintenance agreements (1) (2)
12 (2)10 
Other2 (1)1 
Total$63 $(25)$38 
 December 31, 2017
 Useful Lives Gross Carrying Amount Accumulated Amortization Net Balance
 (in years) (in millions)
Customer relationships15 $86
 $(21) $65
Covenants not to compete4 4
 (2) 2
OtherVarious 15
 (8) 7
Total  $105
 $(31) $74

(1)Related to Energy Systems Group prior to the completion of the sale in June 2023. Amortization ceased at June 30, 2023, the end of the quarter in which the held for sale criteria was met. See Note 4 for further information.
 December 31, 2016
 Useful Lives Gross Carrying Amount Accumulated Amortization Net Balance
 (in years) (in millions)
Customer relationships15 $61
 $(16) $45
Covenants not to compete4 4
 (1) 3
OtherVarious 2
 (1) 1
Total  $67
 $(18) $49

(2)Amortization expense related to the operation and maintenance agreements is included in Non-utility cost of intangible assetsrevenues, including natural gas on CenterPoint Energy’s Statements of Consolidated Income. Amortization ceased at June 30, 2023, the end of the quarter in which the held for sale criteria was $13 million, $4 million and $2 million in the years ended December 31, 2017, 2016 and 2015, respectively. CenterPoint Energy estimates that amortization expense of intangible assets with finite lives will be $12 million, $11 million, $6 million, $6 million and $5 million in the years ending December 31, 2018, 2019, 2020, 2021 and 2022, respectively.met. See Note 4 for further information.


Year Ended December 31,
202320222021
(in millions)
Amortization expense of intangible assets recorded in Depreciation and amortization
$3 $6 $6 
Amortization expense of intangible assets recorded in Non-utility cost of revenues, including natural gas— 1 1 


(6)
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(7) Regulatory AccountingMatters


The following is a list of regulatory assets and liabilities reflected on CenterPoint Energy’sthe Registrants’ respective Consolidated Balance Sheets as of December 31, 20172023 and 2016:2022:

 December 31, 2023
CenterPoint EnergyHouston ElectricCERC
(in millions)
Regulatory Assets:
Future amounts recoverable from ratepayers related to:
Benefit obligations (1)
$379 $— $5 
Asset retirement obligations & other290 75 186 
Net deferred income taxes96 41 42 
Total future amounts recoverable from ratepayers765 116 233 
Amounts deferred for future recovery related to:
Cost recovery riders113 — 73 
Hurricane and February 2021 Winter Storm Event restoration costs149 123 26 
Other regulatory assets147 59 72 
Gas recovery costs27 — 27 
Decoupling17 — 17 
COVID-19 incremental costs12 8 4 
TEEEF costs48 48 — 
Unrecognized equity return (2)
(63)(39)(16)
Total amounts deferred for future recovery450 199 203 
Amounts currently recovered in customer rates related to:
Authorized trackers and cost deferrals535 44 375 
Securitized regulatory assets434 74 — 
Unamortized loss on reacquired debt and hedging106 72 11 
Gas recovery costs34 — 34 
Extraordinary gas costs208 — 208 
Regulatory assets related to TCJA47 47 — 
Hurricane Harvey restoration costs17 17 — 
Benefit obligations11 11 — 
Emergency Generation Costs208 208 — 
Unrecognized equity return (3)
(141)(36)(53)
Total amounts recovered in customer rates (4)
1,459 437 575 
Total Regulatory Assets$2,674 $752 $1,011 
Total Current Regulatory Assets (5)
$161 $— $161 
Total Non-Current Regulatory Assets$2,513 $752 $850 
Regulatory Liabilities:
Regulatory liabilities related to TCJA$1,377 $695 $505 
Estimated removal costs1,322 91 1,150 
Other regulatory liabilities548 245 260 
Total Regulatory Liabilities$3,247 $1,031 $1,915 
Total Current Regulatory Liabilities (6)
$39 $6 $33 
Total Non-Current Regulatory Liabilities$3,208 $1,025 $1,882 

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 December 31,
 2017 2016
 (in millions)
Current regulatory assets (1)
$130
 $70
Non-current regulatory assets:   
Securitized regulatory assets1,590
 1,919
Unrecognized equity return (2)
(287) (329)
Unamortized loss on reacquired debt75
 84
Pension and postretirement-related regulatory asset (3)
646
 809
Hurricane Harvey restoration costs (4)
64
 —
Excess deferred income taxes (5)
48
 —
Other long-term regulatory assets (6)
211
 194
Total non-current regulatory assets2,347
 2,677
Total regulatory assets2,477
 2,747
    
Current regulatory liabilities (7)
24
 18
Non-current regulatory liabilities:   
Excess deferred income taxes (5)
1,354
 —
Estimated removal costs878
 1,010
Other long-term regulatory liabilities232
 288
Total non-current regulatory liabilities2,464
 1,298
Total regulatory liabilities2,488
 1,316
    
Total regulatory assets and liabilities, net$(11) $1,431
 December 31, 2022
CenterPoint EnergyHouston ElectricCERC
(in millions)
Regulatory Assets:
Future amounts recoverable from ratepayers related to:
Benefit obligations (1)
$392 $— $5 
Asset retirement obligations & other237 64 155 
Net deferred income taxes83 34 40 
Total future amounts recoverable from ratepayers712 98 200 
Amounts deferred for future recovery related to:
Extraordinary gas costs1,073 — 1,073 
Cost recovery riders133 — 57 
Hurricane and February 2021 Winter Storm Event restoration costs129 113 16 
Other regulatory assets129 46 67 
Gas recovery costs108 — 108 
Decoupling3 — 3 
COVID-19 incremental costs13 8 5 
TEEEF costs182 182 — 
Unrecognized equity return(54)(27)(5)
Total amounts deferred for future recovery1,716 322 1,324 
Amounts currently recovered in customer rates related to:
Authorized trackers and cost deferrals499 25 369 
Securitized regulatory assets229 229 — 
Unamortized loss on reacquired debt and hedging88 64 12 
Gas recovery costs79 — 30 
Extraordinary gas costs294 — 294 
Regulatory assets related to TCJA47 47 — 
Hurricane Harvey restoration costs30 30 — 
Benefit obligations18 18 — 
Unrecognized equity return (3)
(134)(55)(49)
Total amounts recovered in customer rates
1,150 358 656 
Total Regulatory Assets$3,578 $778 $2,180 
Total Current Regulatory Assets (5)
$1,385 $— $1,336 
Total Non-Current Regulatory Assets$2,193 $778 $844 
Regulatory Liabilities:
Regulatory liabilities related to TCJA$1,436 $716 $536 
Estimated removal costs1,338 158 1,097 
Other regulatory liabilities496 281 193 
Total Regulatory Liabilities$3,270 $1,155 $1,826 
Total Current Regulatory Liabilities (6)
$25 $— $25 
Total Non-Current Regulatory Liabilities$3,245 $1,155 $1,801 

(1)Current regulatory assets are included in Prepaid expenses and other current assets in CenterPoint Energy’s Consolidated Balance Sheets.

(2)
The unrecognized allowed equity return will be recognized as it is recovered in rates through 2024. During the years ended December 31, 2017, 2016 and 2015, Houston Electric recognized approximately $42 million, $64 million and $49 million, respectively, of the allowed equity return. The timing of CenterPoint Energy’s recognition of the allowed equity return will vary each period based on amounts actually collected during the period. The actual amounts recognized are adjusted at least annually to correct any over-collections or under-collections during the preceding 12 months.

(3)NGD’s actuarially determined pension and other postemployment expense in excess of the amount being recovered through rates is being deferred for rate making purposes. Deferred pension and other postemployment expenses of $7 million and $6 million as of December 31, 2017 and 2016, respectively, were not earning a return.

(4)CenterPoint Energy is not earning a return on its Hurricane Harvey restoration costs.

(5)The EDIT will be recovered or refunded to customers as required by tax and regulatory authorities. See Note 14 for additional information.

(6)
Other long-term regulatory assets that are not earning a return were not material as of December 31, 2017 and 2016.

(7)Current regulatory liabilities are included in Other current liabilities in CenterPoint Energy’s Consolidated Balance Sheets.



(1)Pension and postretirement-related regulatory assets balances are actuarially valued annually.

Hurricane Harvey. (2)Represents the following: (a) CenterPoint Energy’s allowed equity return on post in-service carrying cost generally associated with investments in Indiana; (b) Houston Electric’s allowed equity return on TEEEF costs and storm restoration costs; and (c) CERC’s allowed equity return on post in-service carrying cost associated with certain distribution facilities replacements expenditures in Texas.
(3)Represents the following: (a) CenterPoint Energy’s allowed equity return on post in-service carrying cost generally associated with investments in Indiana; (b) Houston Electric’s allowed equity return on its true-up balance of stranded costs, other changes and related interest resulting from the formerly integrated electric delivery systemutilities prior to Texas deregulation to be recovered in rates through 2024 and CERC Corp.’s NGD suffered damage as a result of Hurricane Harvey, a majorcertain storm classified as a Category 4 hurricanerestoration balances; and (c) CERC’s allowed equity return on post in-service carrying cost associated with certain distribution facilities replacements expenditures in Texas.
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(4)Of the Saffir-Simpson Hurricane Wind Scale, that first struck the Texas coast on Friday, August 25, 2017$1.5 billion, $437 million and remained over the Houston area for the next several days. The unprecedented flooding from torrential amounts of rainfall accompanying the storm caused significant damage$575 million currently being recovered in customer rates related to or destruction of residences and businesses served byCenterPoint Energy, Houston Electric and NGD.

Houston Electric estimates that total costs to restore the electric delivery facilities damaged as a result of Hurricane Harvey will be approximately $120CERC, respectively, $459 million, $365 million and estimates that the total restoration costs covered by insurance will be approximately $28 million. NGD estimates that total costs to restore natural gas distribution facilities damaged as$94 million is earning a resultreturn, respectively. The weighted average recovery period of Hurricane Harvey will be approximately $25regulatory assets currently being recovered in base rates, not earning a return, which totals $428 million, $72 million and estimates that the total restoration costs covered by insurance will be approximately $19 million.$320 million for CenterPoint Energy, Houston Electric and NGD will deferCERC, respectively, is 12 years, 28 years and 8 years, respectively. Regulatory assets not earning a return with perpetual or undeterminable lives have been excluded from the uninsured storm restorationweighted average recovery period calculation.
(5)Current regulatory assets for both CenterPoint Energy and CERC include extraordinary gas costs of $86 million and $1,175 million as management believes it isof December 31, 2023 and 2022, respectively.
(6)Current regulatory liabilities are included in Other current liabilities in each of the Registrants’ respective Consolidated Balance Sheets.
The table below reflects the amount of allowed equity return recognized by each Registrant in its Statements of Consolidated Income:
Year Ended December 31,
202320222021
CenterPoint EnergyHouston ElectricCERCCenterPoint EnergyHouston ElectricCERCCenterPoint EnergyHouston ElectricCERC
(in millions)
Allowed equity return recognized$41 $38 $2 $45 $42 $2 $40 $37 $2 

Indiana Electric Securitization of Generation Retirements (CenterPoint Energy)

On January 4, 2023, the IURC issued an order in accordance with Indiana Senate Enrolled Act 386 authorizing the issuance of up to $350 million in securitization bonds to securitize qualified costs associated with the retirements of Indiana Electric’sA.B. Brown coal-fired generation facilities. Accordingly, CenterPoint Energy determined that the retirement of property, plant and equipment became probable that such costs willupon the issuance of the order. No loss on abandonment was recognized in connection with issuance of the order as there was no disallowance of all or part of the cost of the abandoned property, plant and equipment. In the first quarter of 2023, upon receipt of the order, CenterPoint Energy reclassified property, plant and equipment to be recovered through traditional rate adjustment mechanismssecuritization to a regulatory asset and such amounts continued to earn a full return until recovered through securitization.

The SIGECO Securitization Subsidiary issued $341 million aggregate principal amount of the SIGECO Securitization Bonds on June 29, 2023. See Note 13 for capitalfurther details of the issuance of the SIGECO Securitization Bonds. The SIGECO Securitization Subsidiary used a portion of the net proceeds from the issuanceof the SIGECO Securitization Bonds to purchase the securitization property from SIGECO. No gain or loss was recognized.

The SIGECO Securitization Bonds are secured by the securitization property, which includes the right to recover, through non-bypassable securitization charges payable by SIGECO’s retail electric customers, the qualified costs of SIGECO authorized by the IURC order. SIGECO has no payment obligations with respect to the SIGECO Securitization Bonds except to remit collections of securitization charges as set forth in a servicing agreement between SIGECO and through the next base rate proceedingSIGECO Securitization Subsidiary. The non-bypassable securitization charges are subject to a true-up mechanism.

February 2021 Winter Storm Event

In February 2021, certain of the Registrants’ jurisdictions experienced an extreme and unprecedented winter weather event that resulted in prolonged freezing temperatures, which impacted their businesses. The February 2021 Winter Storm Event impacted wholesale prices of CenterPoint Energy’s and CERC’s natural gas purchases and their ability to serve customers in their Natural Gas service territories, including due to the reduction in available natural gas capacity and impacts to CenterPoint Energy’s and CERC’s natural gas supply portfolio activities, and the effects of weather on their systems and their ability to transport natural gas, among other things. The overall natural gas market, including the markets from which CenterPoint Energy and CERC sourced a significant portion of their natural gas for operationtheir operations, experienced significant impacts caused by the February 2021 Winter Storm Event, resulting in extraordinary increases in the cost of natural gas purchased by CenterPoint Energy and maintenance expenses. As a result, storm restorationCERC of approximately $2 billion. CenterPoint Energy and CERC have completed recovery of natural gas costs did not materially affect Houston Electric’s or CERC’s reported net income for 2017.

in Mississippi, Indiana and Texas discussed further below, and continue to recover the natural gas cost in Louisiana and Minnesota. As of December 31, 2017,2023, CenterPoint Energy and CERC have each recorded current regulatory assets of $86 million and non-current regulatory assets of $130 million associated with the February 2021 Winter Storm Event. As of
124

December 31, 2022, CenterPoint Energy and CERC have each recorded current regulatory assets of $1,175 million and non-current regulatory assets of $202 million associated with the February 2021 Winter Storm Event.

In Minnesota, the MPUC issued its written order on October 19, 2022 disallowing CERC’s recovery of approximately $36 million of the $409 million incurred, and CERC’s regulatory asset balance was reduced to reflect the disallowance. CERC filed a petition for reconsideration on November 8, 2022 and a written order denying the petition for reconsideration was issued on January 6, 2023.

On August 24, 2023, the LPSC Staff issued an audit report which recommends some prospective process changes to the gas supply bid process and did not recommend any disallowance of February 2021 Winter Storm Event gas costs incurred in Louisiana. Recovery of such costs remains subject to LPSC approval.On December 19, 2023, the LPSC issued an order which accepted and approved the audit report.
As of both December 31, 2023 and 2022, as authorized by the PUCT, CenterPoint Energy and Houston Electric recorded a regulatory asset of $8 million for bad debt expenses resulting from REPs’ default on their obligation to pay delivery charges to Houston Electric net of collateral. Additionally, as of December 31, 2023 and NGD2022, both CenterPoint Energy and Houston Electric recorded a regulatory asset of $17 million and $16 million, respectively, and will request reimbursement of costs associated with the following:February 2021 Winter Storm Event in Houston Electric’s next rate case.

See Note 15(d) for further information regarding litigation related to the February 2021 Winter Storm Event.

Texas Public Securitization

The Texas Natural Gas Securitization Finance Corporation issued customer rate relief bonds in March 2023, and on March 23, 2023, CenterPoint Energy and CERC, collectively, received approximately $1.1 billion in cash proceeds from the issuance and sale of the state’s customer rate relief bonds. The proceeds from the state’s customer rate relief bonds included carrying costs incurred through August 2022. Incremental carrying costs incurred after August 2022 until the date the proceeds were received are recorded in a separate regulatory asset; the current Texas Gas rate proceeding includes a request for recovery of this regulatory asset. As CenterPoint Energy and CERC have no future financial obligations for the repayment of the state’s customer rate relief bonds, the customer rate relief bonds are not recorded on CenterPoint Energy’s or CERC’s balance sheets. The $1.1 billion in cash proceeds from the state’s customer rate relief bonds is considered to be a government grant. The state’s customer rate relief bonds are backed in part by customer rate relief property, including customer rate relief charges, which are non-bypassable uniform monthly volumetric charges to be paid by all existing and future customers as a component of each regulated utility’s gas cost, separate from their base rate. CERC only acts as a collection agent, whose duties include management, servicing and administration of a portion of the customer rate relief property which is associated with the customer rate relief charge imposed on customers of CERC under the guidance and direction from the Railroad Commission. The Texas Natural Gas Securitization Finance Corporation, and not CenterPoint Energy or CERC, is the owner of the customer rate relief property. The assets of the Texas Natural Gas Securitization Finance Corporation are not available to pay creditors of CenterPoint Energy, CERC, or their affiliates. While the customer rate relief charges will be included by CERC in their monthly billings, the billing amount is established by the Railroad Commission. CERC will remit all customer rate relief charges to the financing entity set up by the Railroad Commission. Therefore, the collection and servicing of customer rate relief charges have no impact on the respective Statements of Consolidated Income of CenterPoint Energy or CERC.

As U.S. generally accepted accounting principles have no specific accounting guidance for government grants or assistance, the cash proceeds from the state’s customer rate relief bonds were accounted for as a government grant by analogy to the grant model under IAS 20—Accounting for Government Grants and Disclosures of Government Assistance. CenterPoint Energy and CERC reflect the proceeds from the grant as a deduction to natural gas costs and recognized the $1.1 billion of cash proceeds from the state’s customer rate relief bonds within Utility natural gas expense on their respective Statements of Consolidated Income in the year ended December 31, 2023, net of the recognition of natural gas cost related to relieving CenterPoint Energy and CERC’s regulatory assets related to the February 2021 Winter Storm Event in the same period.

Houston Electric TEEEF

Pursuant to legislation passed in 2021, Houston Electric entered into two leases for TEEEF (mobile generation) which are detailed in Note 20. Houston Electric initially sought recovery of the lease costs and the applicable return as of December 31, 2021 under these lease agreements of approximately $200 million in its DCRF application field with the PUCT on April 5, 2022, and subsequently amended on July 1, 2022, to show mobile generation in a separate Rider TEEEF. A final order was issued on April 5, 2023 approving a reduced revenue requirement of $39 million that results in full recovery of costs requested
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  Houston Electric NGD
  (in millions)
Property, plant and equipment $42
 $5
Insurance proceeds received (11) —
Insurance receivable —
 (5)
    Net property, plant and equipment $31
 $—
     
Operation and maintenance expense $75
 $10
Insurance proceeds received (3) —
Insurance receivable (14) (4)
    Net regulatory asset $58
 $6
but lengthens the amortization period for the short-term lease to be collected over 82.5 months. On May 25, 2023, the PUCT issued its order on rehearing which clarified some of the findings, but did not change the approval of TEEEF cost recovery. Additional motions for rehearing were filed and the PUCT issued an order on August 3, 2023 denying the motions for rehearing. The deadline for a party to file a judicial appeal of the PUCT’s decision was September 5, 2023, and no appeal was filed. As such, the PUCT’s decision on the first TEEEF filing is now final and non-appealable.


On April 5, 2023, Houston Electric made its second TEEEF filing requesting recovery of TEEEF related costs incurred through December 31, 2022. Houston Electric is requesting a new annual revenue requirement of approximately $188 million using 78 months to amortize the related deferred costs for proposed rates beginning September 2023, a net increase in TEEEF revenues of approximately $149 million. On June 7, 2023, intervenors jointly requested a hearing, and on June 14, 2023, the PUCT staff indicated that it does not oppose a hearing in this docket. On June 21, 2023 Houston Electric made a filing that a hearing is not necessary given the PUCT’s decision in the TEEEF docket filed in 2022 and indicated that if the PUCT does refer this case to the State Office of Administrative Hearings, any preliminary order issued by the PUCT should be limited. On July 18, 2023 the PUCT referred the case to the State Office of Administrative Hearings and, on July 20, 2023, the PUCT issued a preliminary order identifying the issues to be addressed. On August 28, 2023, the State Office of Administrative Hearings issued an Order setting interim rates to collect an annual revenue requirement at the filed amount. Interim rates became effective on September 1, 2023 and are subject to surcharge or refund if they differ from the final rates approved by the PUCT. On October 12, 2023, a joint motion to abate was filed because the parties reached an agreement in principle on all issues.The agreement in principle reduces the annual revenue requirement by approximately $35 million based on recovering the balance as of December 31, 2022 over a 102 month amortization period (instead of the 78 month period in the initial filing) and also allows for revised interim rates (to incorporate the agreement in principle and the initial interim rates that have been in place since September 1, 2023). The updated interim rates were implemented December 15, 2023. The agreement in principle is subject to PUCT approval which was granted in its order issued on February 1, 2024.
(7)
Houston Electric defers costs associated with the short-term and long-term leases that are probable of recovery and would otherwise be charged to expense in a regulatory asset, including allowed debt returns, and determined that such regulatory assets remain probable of recovery as of December 31, 2023. Right of use finance lease assets, such as assets acquired under the long-term leases, are evaluated for impairment under the long-lived asset impairment model by assessing if a capital disallowance from a regulator is probable through monitoring the outcome of rate cases and other proceedings. Houston Electric continues to monitor the on-going proceedings and did not record any impairments on its right of use assets in the years ended December 31, 2023 or 2022. See Note 20 for further information.

(8) Stock-Based Incentive Compensation Plans and Employee Benefit Plans


(a) Stock-Based Incentive Compensation Plans (CenterPoint Energy)


CenterPoint Energy has LTIPs that provide for the issuance of stock-based incentives, including stock options, performance awards, restricted stock unit awards and restricted and unrestricted stock awards to officers, employees and non-employee directors. Approximately 1430 million shares of CenterPoint Energy common stockCommon Stock are authorized under these plans for awards.

CenterPoint Energy issues new shares of its Common Stock to satisfy stock-based payments related to LTIPs. Equity awards are granted to employees without cost to the participants. The performance awards granted in 2017, 2016 and 2015 are distributed based upon the achievement of certain objectives over a three-year performance cycle. The stock awards granted in 2017, 2016 and 2015 are service based. The stock awards generally vest at the end of a three-year period. Upon vesting, both the performance and stock awards are issued to the participants along with the value of dividend equivalents earned over the performance cycle or vesting period. CenterPoint Energy issues new shares to satisfy stock-based payments related to LTIPs.

CenterPoint Energy recorded LTIP compensation expense of $21 million, $19 million and $17 million for the years ended December 31, 2017, 2016 and 2015, respectively.  This expense is included in Operation and Maintenance Expense in the Statements of Consolidated Income.

The total income tax benefit recognized related to LTIPs was $8 million, $7 million and $6 million for the years ended December 31, 2017, 2016 and 2015, respectively. No compensation cost related to LTIPs was capitalized as a part of inventory or fixed assets in 2017, 2016 or 2015. The actual tax benefit realized for tax deductions related to LTIPs totaled $6 million, $5 million and $6 million for 2017, 2016 and 2015, respectively.


Compensation costs for the performance awards and stock unit awards granted under LTIPs are measured using fair value and expected achievement levels on the grant date. For performance awards with operational goals, the achievement levels are revised as goals are evaluated. The fair value of awards granted to employees is based on the closing stock price of CenterPoint Energy’s common


stockCommon Stock on the grant date. The compensation expense is recorded on a straight-line basis over the vesting period. Forfeitures are estimated on the date of grant based on historical averages and estimates are updated periodically throughout the vesting period. 
 
The performance awards granted in 2023, 2022 and 2021 are distributed based upon the achievement of certain objectives over a three-year performance cycle. The stock unit awards granted in 2023, 2022 and 2021 are service based, subject to the achievement of a performance goal. The stock unit awards generally vest at the end of a three-year period; however, stock unit awards granted to non-employee directors vest immediately upon grant. Upon vesting, shares of the performance awards and stock unit awards are issued to the participants along with the value of dividend equivalents earned over the performance cycle or vesting period.

126

The following table summarizes CenterPoint Energy’s expenses related to LTIPs for 2023, 2022 and 2021:
Year Ended December 31,
202320222021
(in millions)
LTIP compensation expense (1)
$65 $51 $48 
Income tax benefit recognized15 12 11 
Actual tax benefit realized for tax deductions17 6 4 

(1)Amounts presented in the table above are included in Operation and maintenance expense in CenterPoint Energy’s Statements of Consolidated Income and shown prior to any amounts capitalized.
The following tables summarize CenterPoint Energy’s LTIP activity for 2017:2023

 Year Ended December 31, 2023
 Shares
(Thousands)		Weighted-Average
Grant Date
Fair Value		Remaining Average
Contractual
Life (Years)
Aggregate
Intrinsic
Value (2) (Millions)
Performance Awards (1)
Outstanding and nonvested as of December 31, 20225,157 $24.26   
Granted1,960 29.18   
Forfeited or canceled(291)27.38   
Vested and released to participants(1,601)23.08   
Outstanding and nonvested as of December 31, 20235,225 $25.95 1.1$101 
Stock Unit Awards
Outstanding and nonvested as of December 31, 20222,296 $25.03 
Granted606 30.83 
Forfeited or canceled(93)27.10 
Vested and released to participants(948)24.48 
Outstanding and nonvested as of December 31, 20231,861 $26.91 0.7$53 
Performance Awards
 Outstanding and Non-Vested Shares
 Year Ended December 31, 2017
 
Shares
(Thousands)
 
Weighted-Average
Grant Date
Fair Value
 
Remaining Average
Contractual
Life (Years)
 
Aggregate
Intrinsic
Value (Millions)
Outstanding as of December 31, 20163,423
 $20.90
    
Granted1,263
 26.64
    
Forfeited or canceled(846) 23.38
    
Vested and released to participants(213) 23.68
    
Outstanding as of December 31, 20173,627
 22.15
 1 $51
The outstanding and non-vested shares displayed in the table above assumes that shares are issued at the(1)Reflects maximum performance level. The aggregate intrinsic value reflectsachievement.
(2)Reflects the impact of current expectations of achievement and stock price.


Additional information related to the Performance Awards and Stock Unit Awards is as follows:
 Outstanding and Non-Vested Shares
 Year Ended December 31, 2017
 
Shares
(Thousands)
 
Weighted-Average
Grant Date
Fair Value
 
Remaining Average
Contractual
Life (Years)
 
Aggregate
Intrinsic
Value (Millions)
Outstanding as of December 31, 2016920
 $20.74
    
Granted414
 26.77
    
Forfeited or canceled(47) 22.25
    
Vested and released to participants(307) 22.46
    
Outstanding as of December 31, 2017980
 22.68
 1.2 $28

The weighted-average grant-date fair values per unit of awards granted were as follows for 2017, 2016 and 2015:
 Year Ended December 31,
 2017 2016 2015
Performance awards$26.64
 $18.98
 $21.28
Stock awards26.77
 19.24
 21.39
 Year Ended December 31,
 202320222021
(in millions, except for per unit amounts)
Performance Awards
Weighted-average grant date fair value per unit of awards granted$29.18 $28.12 $21.89 
Total intrinsic value of awards received by participants47 13 7 
Vested grant date fair value37 13 8 
Stock Unit Awards
Weighted-average grant date fair value per unit of awards granted$30.83 $28.44 $24.20 
Total intrinsic value of awards received by participants28 14 11 
Vested grant date fair value23 13 11 
 
Valuation Data

The total intrinsic valueAs of awards received by participants was as follows for 2017, 2016 and 2015:
 Year Ended December 31,
 2017 2016 2015
 (in millions)
Performance awards$7
 $7
 $9
Stock awards9
 6
 7

The total grant date fair value of performance and stock awards which vested during the years ended December 31, 2017, 2016 and 2015 was $12 million, $13 million and $13 million, respectively.  As of December 31, 2017,2023, there was $24$36 million of total unrecognized compensation cost related to non-vestednonvested performance and stock unit awards which is expected to be recognized over a weighted-average period of 1.7 years.



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(b) Pension and Postretirement Benefits (CenterPoint Energy)


CenterPoint Energy maintains a non-contributory qualified defined benefit pension plan covering substantially alleligible employees and is closed to new participants, with benefits determined using a cash balance formula. Under the cash balance formula, participants accumulate a retirement benefit based upon 5% of eligible earnings and accrued interest. Participants are 100% vested in their benefit after completing three years of service. In addition to the non-contributory qualified defined benefit pension plan, CenterPoint Energy maintains unfunded non-qualified benefit restoration plans which allow participants to receive the benefits to which they would have been entitled under CenterPoint Energy’s non-contributory qualified pension plan except for federally mandated limits on qualified plan benefits or on the level of compensation on which qualified plan benefits may be calculated.


CenterPoint Energy provides certain healthcarealso maintains three additional qualified defined benefit pension plans, two of which are closed to new participants and lifeone of which is completely frozen, and a non-qualified supplemental retirement plan. The defined benefit pension plans cover eligible full-time regular employees and retirees of Vectren and are primarily non-contributory.

In December 2022, the CenterPoint Energy pension plan completed an annuity lift-out, a transaction that provided for the purchase of an irrevocable group annuity contract to fund pension plan annuities of retirees from previously divested businesses, as part of a de-risking strategy. This annuity lift-out reduced the plan’s pension obligation by $138 million and plan assets by $136 million which were transferred to an insurance benefits for retired employees on bothcompany. The $138 million transferred benefit obligation represented 9.4% of CenterPoint Energy’s total benefit obligation as of its last remeasurement prior to the transaction. As a contributory and non-contributory basis. Employees hired before January 1, 2018 become eligibleresult of this transaction, CenterPoint Energy incurred a settlement charge of $47 million. In addition, CenterPoint Energy was relieved of all responsibility for these pension obligations’ and an insurance company is now required to pay and administer the retirement benefits if they have met certain ageowed to 1,119 retirees and service requirements at retirement, as defined in the plans. Employees hired on or after January 1, 2018 are not eligible for these benefits, except for those employees represented by IBEW. Benefit costs are accrued over the active service period of employees. Effective January 1, 2017, members of the IBEW Local Union 66 who retire on or after January 1, 2017, and their dependents, will receive any retiree medical and prescription drug benefits exclusively through the NECA/IBEW Family Medical Care Plan pursuantbeneficiaries, with no changes to the termsamount, timing or form of the renegotiated collective bargaining agreement entered into in May 2016.   retirement benefit payments.


CenterPoint Energy’s net periodic cost includes the following components relating to pension, including the non-qualified benefit restorationplans:
 Year Ended December 31,
 202320222021
 (in millions)
Service cost (1)
$25 $29 $39 
Interest cost (2)
76 73 59 
Expected return on plan assets (2)
(76)(87)(103)
Amortization of net loss (2)
28 31 36 
Settlement cost (2) (3)
— 126 38 
Net periodic cost$53 $172 $69 
(1)Amounts presented in the table above are included in Operation and maintenance expense in CenterPoint Energy’s Statements of Consolidated Income, net of regulatory deferrals and amounts capitalized.
(2)Amounts presented in the table above are included in Other, net in CenterPoint Energy’s Statements of Consolidated Income, net of regulatory deferrals.
(3)A one-time, non-cash settlement cost is required when the total lump sum distributions or other settlements of plan benefit obligations during a plan year exceed the service cost and postretirement benefits:interest cost components of the net periodic cost for that year. In 2023, 2022 and 2021, CenterPoint Energy recognized non-cash settlement cost due to lump sum settlement payments. The transfer of assets related to the 2022 Annuity Lift-Out is considered a lump sum settlement payment.
 Year Ended December 31,
 2017 2016 2015
 Pension
Benefits		 Post-retirement
Benefits		 
Pension
Benefits
 
Post-retirement
Benefits
 
Pension
Benefits
 
Post-retirement
Benefits
 (in millions)
Service cost$36
 $2
 $38
 $2
 $41
 $2
Interest cost89
 16
 93
 16
 93
 20
Expected return on plan assets(97) (5) (101) (6) (120) (7)
Amortization of prior service cost (credit)9
 (5) 9
 (3) 9
 (1)
Amortization of net loss58
 —
 63
 1
 57
 5
Curtailment (1)
—
 —
 —
 (5) —
 —
Settlement (2)
—
 —
 —
 —
 10
 —
Net periodic cost$95
 $8
 $102
 $5
 $90
 $19

(1)A curtailment gain or loss is required when the expected future services of a significant number of current employees are reduced or eliminated for the accrual of benefits. During 2016, postretirement healthcare benefits were amended resulting in a net curtailment gain of $5 million. In May 2016, Houston Electric entered into a renegotiated collective bargaining agreement with the IBEW Local Union 66 that provides that for Houston Electric union employees covered under the agreement who retire on or after January 1, 2017, retiree medical and prescription drug coverage will be provided exclusively through the NECA/IBEW Family Medical Care Plan in exchange for the payment of monthly premiums as determined under the agreement. As a result, the accrued postretirement benefits related to such future Houston Electric union retirees were eliminated. Houston Electric recognized a curtailment gain of $3 million as an accelerated recognition of the prior service credit that would otherwise be recognized in future periods for the postretirement plan. CenterPoint Energy also recognized an additional curtailment gain of $2 million in October 2016 related to other amendments in the postretirement plan. As a result of these amendments, the 2016 postretirement expense was significantly lower than expenses reported for previous years.

(2)A one-time, non-cash settlement charge is required when lump sum distributions or other settlements of plan benefit obligations during a plan year exceed the service cost and interest cost components of net periodic cost for that year.  Due to the amount of lump sum payment distributions from the non-qualified pension plan during the year ended December 31, 2015, CenterPoint Energy recognized a non-cash settlement charge of $10 million.  This charge is an acceleration of costs that would otherwise be recognized in future periods. 




CenterPoint Energy used the following assumptions to determine net periodic cost relating to pension and postretirement benefits:
 Year Ended December 31,
 202320222021
Discount rate5.15 %2.80 %2.45 %
Expected return on plan assets6.50 5.00 5.00 
Rate of increase in compensation levels4.99 4.95 5.05 
 Year Ended December 31,
 2017 2016 2015
 Pension
Benefits		 Post-retirement
Benefits		 
Pension
Benefits
 
Post-retirement
Benefits
 Pension
Benefits		 Post-retirement
Benefits
Discount rate4.15% 4.15% 4.40% 4.35% 4.05% 3.90%
Expected return on plan assets6.00
 4.50
 6.25
 4.80
 6.50
 5.20
Rate of increase in compensation levels4.50
 —
 4.15
 —
 4.00
 —


In determining net periodic benefitsbenefit cost, CenterPoint Energy uses fair value, as of the beginning of the year, as its basis for determining expected return on plan assets except for two of Vectren’s qualified defined benefit pension plans which use a market related value of assets.


128

The following table summarizes changes in the benefit obligation, plan assets, the amounts recognized in consolidated balance sheets andthe Consolidated Balance Sheets as well as the key assumptions of CenterPoint Energy’s pension including benefit restoration, and postretirement plans. The measurement dates for plan assets and obligations were December 31, 20172023 and 2016.2022.
 December 31,
 20232022
 (in millions, except for actuarial assumptions)
Change in Benefit Obligation 
Benefit obligation, beginning of year$1,553 $2,298 
Service cost25 29 
Interest cost76 73 
Benefits paid (4)
(147)(509)
Actuarial (gain) loss (1)
41 (338)
Plan amendment— — 
Benefit obligation, end of year1,548 1,553 
Change in Plan Assets  
Fair value of plan assets, beginning of year1,212 2,072 
Employer contributions32 35 
Benefits paid (4)
(147)(509)
Actual investment return107 (386)
Fair value of plan assets, end of year1,204 1,212 
Funded status, end of year$(344)$(341)
Amounts Recognized in Balance Sheets  
Non-current assets$4 $— 
Current liabilities-other(7)(7)
Other liabilities-benefit obligations(341)(334)
Net liability, end of year$(344)$(341)
Actuarial Assumptions
Discount rate (2)
4.95 %5.15 %
Expected return on plan assets (3)
6.50 6.50 
Rate of increase in compensation levels4.97 4.99 
Interest crediting rate3.00 3.00 
 December 31,
 2017 2016
 Pension
Benefits		 Post-retirement
Benefits		 
Pension
Benefits
 
Post-retirement
Benefits
 (in millions, except for actuarial assumptions)
Change in Benefit Obligation       
Benefit obligation, beginning of year$2,197
 $383
 $2,193
 $432
Service cost36
 2
 38
 2
Interest cost89
 16
 93
 16
Participant contributions—
 7
 —
 10
Benefits paid(168) (26) (181) (37)
Actuarial loss71
 4
 54
 13
Medicare reimbursement—
 —
 —
 3
Plan amendment (1)
—
 —
 —
 (56)
Benefit obligation, end of year2,225
 386
 2,197
 383
Change in Plan Assets 
  
  
  
Fair value of plan assets, beginning of year1,656
 113
 1,679
 136
Employer contributions48
 16
 9
 18
Participant contributions—
 7
 —
 10
Benefits paid(168) (26) (181) (37)
Plan amendment (2)
—
 —
 —
 (20)
Actual investment return265
 10
 149
 6
Fair value of plan assets, end of year1,801
 120
 1,656
 113
Funded status, end of year$(424) $(266) $(541) $(270)
Amounts Recognized in Balance Sheets 
  
  
  
Current liabilities-other$(7) $(6) $(7) $(6)
Other liabilities-benefit obligations(417) (260) (534) (264)
Net liability, end of year$(424) $(266) $(541) $(270)



 December 31,
 2017 2016
 Pension Benefits Post-retirement
Benefits		 Pension Benefits Post-retirement
Benefits
Actuarial Assumptions       
Discount rate3.65% 3.60% 4.15% 4.15%
Expected return on plan assets6.00
 4.55
 6.00
 4.50
Rate of increase in compensation levels4.45
 —
 4.50
 —
Medical cost trend rate assumed for the next year - Pre-65—
 6.15
 —
 5.75
Medical/prescription drug cost trend rate assumed for the next year - Post-65—
 23.85
 —
 10.65
Prescription drug cost trend rate assumed for the next year - Pre-65—
 9.85
 —
 10.75
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)—
 4.50
 —
 4.50
Year that the cost trend rates reach the ultimate trend rate - Pre-65—
 2026
 —
 2024
Year that the cost trend rates reach the ultimate trend rate - Post-65—
 2024
 —
 2024

(1)The postretirement benefits were amended during 2016 to change retiree medical coverage, effective January 1, 2017, as follows: (i) members of the IBEW Local Union 66 who retire on or after January 1, 2017, and their dependents, will receive any retiree medical and prescription drug coverage exclusively through the NECA/IBEW Family Medical Care Plan pursuant to the terms of the renegotiated collective bargaining agreement entered into in May 2016; and (ii)  Medicare eligible post-65 retirees will receive coverage through a Medicare Advantage Program, an insured benefit, in lieu of the previous self-insured benefit.  These changes resulted in a reduction in our postretirement plan liability of $56 million as of December 31, 2016.

(2)In May 2016, Houston Electric entered into a renegotiated collective bargaining agreement with the IBEW Local Union 66. The Houston Lighting & Power Company Union Retirees’ Medical and Dental Benefits Trust was amended to reflect the renegotiated collective bargaining agreement by establishing a segregated and restricted account under the trust for the retiree medical benefits of post-2016 union retirees who are now covered exclusively by the NECA/IBEW Family Medical Care Plan. $20 million was transferred to the account for post-2016 union retirees.

The accumulated benefit obligation(1)Significant sources of loss for all defined benefit pension plans was $2,164 million and $2,168 million as2023 include the decrease in discount rate from 5.15% to 4.95%, partially offset by significant sources of December 31, 2017 and 2016, respectively.
The expected rate ofgain that include actual return assumption was developed using the targeted asset allocation of CenterPoint Energy’s plans and theon assets exceeding expected return for each asset class.on plan assets during 2023.

(2)The discount rate assumption was determined by matching the projected cash flows of CenterPoint Energy’s plans against a hypothetical yield curve of high-quality corporate bonds represented by a series of annualized individual discount rates from one-half to 99 years.

For measurement purposes, medical and prescription drug costs are assumed to increase to 6.15% and 9.85%, respectively, for(3)The expected rate of return assumption was developed using the pre-65 retirees,targeted asset allocation of CenterPoint Energy’s plans and the combined medical/prescription drug cost increase is assumed to be 23.85%expected return for the post-65 retirees during 2018, after which these rates decrease until reaching the ultimate trend rate of 4.50% in 2026 and 2024each asset class.
(4)Benefits paid for the pre-65 and post-65 retirees, respectively.



CenterPoint Energy’s changes in accumulated comprehensive loss2022 includes $136 million related to defined benefit, postretirement and other postemployment plans are as follows:the 2022 Annuity Lift-Out.
 Year Ended December 31,
 2017 2016
 (in millions)
Beginning Balance$(72) $(65)
Other comprehensive income (loss) before reclassifications (1)
4
 (19)
Amounts reclassified from accumulated other comprehensive income:   
Prior service cost (2)
1
 —
Actuarial losses (2)
7
 8
Total reclassifications from accumulated other comprehensive income8
 8
Tax benefit (expense)(6) 4
Net current period other comprehensive income (loss)6
 (7)
Ending Balance$(66) $(72)

(1)Total other comprehensive income (loss) related to the remeasurement of pension, postretirement and other postemployment plans.

(2)These accumulated other comprehensive components are included in the computation of net periodic cost.

Amounts recognized in accumulated other comprehensive loss consist of the following:
 December 31,
 2017 2016
 
Pension
Benefits
 
Postretirement
Benefits
 
Pension
Benefits
 
Postretirement
Benefits
 (in millions)
Unrecognized actuarial loss (gain)$94
 $(8) $100
 $3
Unrecognized prior service cost1
 6
 2
 6
Net amount recognized in accumulated other comprehensive loss (gain)$95
 $(2) $102
 $9

The changes in plan assets and benefit obligations recognized in other comprehensive income during 2017 are as follows:
 
Pension
Benefits
 
Postretirement
Benefits
 (in millions)
Net loss (gain)$1
 $(10)
Amortization of net loss(7) —
Amortization of prior service cost(1) (1)
Total recognized in comprehensive income$(7) $(11)

The total expense recognized in net periodic costs and other comprehensive income was $88 million and $(3) million for pension and postretirement benefits, respectively, for the year ended December 31, 2017.

The amounts in accumulated other comprehensive loss expected to be recognized as components of net periodic benefit cost during 2018 are as follows:
 
Pension
Benefits
 
Postretirement
Benefits
 (in millions)
Unrecognized actuarial loss$6
 $—
Unrecognized prior service cost1
 1
Amounts in accumulated comprehensive loss to be recognized in net periodic cost in 2018 (1)
$7
 $1



(1)Upon adoption of ASU 2017-07 on January 1, 2018, these amounts will be recognized as Other Income (Expense) in CenterPoint Energy’s Statements of Consolidated Income.


The following table displays pension benefits related to CenterPoint Energy’s pension plans that have accumulated benefit obligations in excess of plan assets:
 December 31,
 20232022
 Pension
(Qualified)		Pension
(Non-qualified)		Pension
(Qualified)		Pension
(Non-qualified)
 (in millions)
Accumulated benefit obligation$1,496 $48 $1,497 $51 
Projected benefit obligation1,500 48 1,502 51 
Fair value of plan assets1,204 — 1,212 — 

129

 December 31,
 2017 2016
 
Pension
Qualified
 
Pension
Non-qualified
 
Pension
Qualified
 
Pension
Non-qualified
 (in millions)
Accumulated benefit obligation$2,090
 $74
 $2,097
 $71
Projected benefit obligation2,151
 74
 2,126
 71
Fair value of plan assets1,801
 —
 1,656
 —

Assumed healthcare cost trend rates have a significant effectThe accumulated benefit obligation for all defined benefit pension plans on the reported amounts for CenterPoint Energy’s Consolidated Balance Sheets was $1,544 million and $1,548 million as of December 31, 2023 and 2022, respectively.
(c) Postretirement Benefits

CenterPoint Energy provides certain healthcare and life insurance benefits for eligible retired employees on both a contributory and non-contributory basis. The Registrants’ employees (other than employees of Vectren and its subsidiaries) who were hired before January 1, 2018 and who have met certain age and service requirements at retirement, as defined in the plans, are eligible to participate in these benefit plans, provided, however, that life insurance benefits are available only for eligible retired employees who retired before January 1, 2022. Employees hired on or after January 1, 2018 are not eligible for these benefits, except that such employees represented by IBEW Local Union 66 are eligible to participate in certain of the benefits, subject to the applicable age and service requirements. With respect to retiree medical and prescription drug benefits, and, effective January 1, 2021, dental and vision benefits, employees represented by the IBEW Local Union 66 who retire on or after January 1, 2017, and their dependents, receive any such benefits exclusively through the NECA/IBEW Family Medical Care Plan pursuant to the terms of the applicable collective bargaining agreement. Houston Electric and CERC are required to fund a portion of their obligations in accordance with rate orders. All other obligations are funded on a pay-as-you-go basis.

CenterPoint Energy, through Vectren, also maintains a postretirement benefit plans. A 1% changeplan that provides health care and life insurance benefits, which are a combination of self-insured and fully insured programs, to eligible Vectren retirees on both a contributory and non-contributory basis.

Postretirement benefits are accrued over the active service period of employees. The net postretirement benefit cost includes the following components:
 Year Ended December 31,
 202320222021
 CenterPoint EnergyHouston ElectricCERCCenterPoint EnergyHouston ElectricCERCCenterPoint EnergyHouston ElectricCERC
 (in millions)
Service cost (1)
$1 $— $1 $2 $— $1 $2 $— $1 
Interest cost (2)
13 559 4 3 9 4 3 
Expected return on plan assets (2)
(5)(4)(1)(5)(4)(1)(4)(3)(1)
Amortization of prior service cost (credit) (2)
(2)(5)2(3)(4)2 (4)(5)1 
Amortization of net loss (2)(8)(4)(3)(4)(2)(1)— — — 
Net postretirement benefit cost (credit)$(1)$(8)$4 $(1)$(6)$4 $3 $(4)$4 

(1)Amounts presented in the assumed healthcaretable above are included in Operation and maintenance expense in each of the Registrants’ respective Statements of Consolidated Income, net of regulatory deferrals and amounts capitalized.
(2)Amounts presented in the table above are included in Other, net in each of the Registrants’ respective Statements of Consolidated Income, net of regulatory deferrals.

The following assumptions were used to determine net periodic cost trendrelating to postretirement benefits:
 Year Ended December 31,
 202320222021
CenterPoint EnergyHouston ElectricCERCCenterPoint EnergyHouston ElectricCERCCenterPoint EnergyHouston ElectricCERC
Discount rate5.15 %5.15 %5.15 %2.85 %2.85 %2.85 %2.50 %2.50 %2.50 %
Expected return on plan assets5.13 5.26 4.69 3.22 3.32 2.86 3.20 3.30 2.85 


130

The following table summarizes changes in the benefit obligation, plan assets, the amounts recognized in consolidated balance sheets and the key assumptions of the postretirement plans. The measurement dates for plan assets and benefit obligations were December 31, 2023 and 2022.
 December 31,
 20232022
 CenterPoint EnergyHouston ElectricCERCCenterPoint EnergyHouston ElectricCERC
 (in millions, except for actuarial assumptions)
Change in Benefit Obligation  
Benefit obligation, beginning of year$263 $115 $92 $336 $148 $118 
Service cost1 — 1 2 — 1 
Interest cost13 5 5 9 4 3 
Participant contributions6 2 3 6 2 3 
Benefits paid(20)(8)(8)(20)(7)(8)
Plan amendment— — — 3 — 2 
Actuarial (gain) loss (1)— (1)— (73)(32)(27)
Benefit obligation, end of year263 113 93 263 115 92 
Change in Plan Assets   
Fair value of plan assets, beginning of year109 84 25 132 104 29 
Employer contributions7 — 4 8 1 4 
Participant contributions6 2 3 6 2 3 
Benefits paid(20)(8)(8)(20)(7)(8)
Actual investment return10 8 2 (17)(16)(3)
Fair value of plan assets, end of year112 86 26 109 84 25 
Funded status, end of year$(151)$(27)$(67)$(154)$(31)$(67)
Amounts Recognized in Balance Sheets   
Current liabilities — other$(7)$— $(4)$(7)$— $(4)
Other liabilities — benefit obligations(144)(27)(63)(147)(31)(64)
Net liability, end of year$(151)$(27)$(67)$(154)$(31)$(68)
Actuarial Assumptions
Discount rate (2)4.95 %4.95 %4.95 %5.15 %5.15 %5.15 %
Expected return on plan assets (3)5.13 5.26 4.69 3.66 3.75 3.35 
Medical cost trend rate assumed for the next year - Pre-657.25 7.25 7.25 6.50 6.50 6.50 
Medical/prescription drug cost trend rate assumed for the next year - Post-6522.76 22.76 22.76 23.66 23.66 23.66 
Prescription drug cost trend rate assumed for the next year - Pre-659.00 9.00 9.00 8.00 8.00 8.00 
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)4.50 4.50 4.50 4.50 4.50 4.50 
Year that the cost trend rates reach the ultimate trend rate - Pre-65203320332033203220322032
Year that the cost trend rates reach the ultimate trend rate - Post-65203320332033203220322032

(1)Significant sources of loss for 2023 include updated life insurance rates and the decrease in discount rate would havefrom 5.15% to 4.95%.
(2)The discount rate assumption was determined by matching the following effects:projected cash flows of the plans against a hypothetical yield curve of high-quality corporate bonds represented by a series of annualized individual discount rates from one-half to 99 years.
(3)The expected rate of return assumption was developed using the targeted asset allocation of the plans and the expected return for each asset class.



131

 
1%
Increase
 
1%
Decrease
 (in millions)
Effect on postretirement benefit obligation$12
 $11
Effect on total of service and interest cost—
 —
(d) Accumulated Other Comprehensive Income (Loss) (CenterPoint Energy and CERC)


CenterPoint Energy recognizes the funded status of its pension and other postretirement plans on its Consolidated Balance Sheets. To the extent this obligation exceeds amounts previously recognized in the Statements of Consolidated Income, CenterPoint Energy records a regulatory asset for that portion related to its rate-regulated utilities. To the extent that excess liability does not relate to a rate-regulated utility, the offset is recorded as a reduction to equity in accumulated other comprehensive income.

Amounts recognized in accumulated other comprehensive loss (gain) consist of the following:
 December 31,
 20232022
 Pension
Benefits		Postretirement
Benefits		Pension
Benefits		Postretirement
Benefits
CenterPoint EnergyCenterPoint EnergyCERCCenterPoint EnergyCenterPoint EnergyCERC
 (in millions)
Unrecognized actuarial loss (gain)$69 $(34)$(27)$70 $(36)$(28)
Unrecognized prior service cost— 12 10 — 13 11 
Net amount recognized in accumulated other comprehensive loss (gain)$69 $(22)$(17)$70 $(23)$(17)

The changes in plan assets and benefit obligations recognized in other comprehensive income during 2023 are as follows:
 Pension
Benefits		Postretirement
Benefits
CenterPoint EnergyCenterPoint EnergyCERC
(in millions)
Net loss (gain)$2 $— $1 
Amortization of net loss(3)2 (2)
Amortization of prior service cost— (1)1 
Settlement— — — 
Total recognized in comprehensive income$(1)$1 $— 
Total recognized in net periodic costs and Other comprehensive income$52 $— $4 

(e) Pension Plan Assets (CenterPoint Energy)

In managing the investments associated with the benefit plans, CenterPoint Energy’s objective is to achieve and maintain a fully funded plan. This objective is expected to be achieved through an investment strategy that manages liquidity requirements while maintaining a long-term horizon in making investment decisions and efficient and effective management of plan assets.


As part of the investment strategy discussed above, CenterPoint Energy maintained the following weighted averageweighted-average allocation targets for its benefitpension plans as of December 31, 2017:2023:
MinimumMaximum
U.S. equity17 %27 %
International equity9 %19 %
Real estate2 %11 %
Fixed income54 %64 %
Cash— %2 %
132

Pension
Benefits
Postretirement
Benefits
U.S. equity12 – 28%13 – 23%
International developed market equity7 – 17%3 – 13%
Emerging market equity3 – 13%—
Fixed income54 – 66%69 – 79%
Cash0 – 2%0 – 2%



The following tables set forth by level, within the fair value hierarchy (see Note 9)10), CenterPoint Energy’s pension plan assets at fair value as of December 31, 20172023 and 2016:2022:
Fair Value Measurements as of December 31,
20232022
 (Level 1)(Level 2)(Level 3)Total(Level 1)(Level 2)(Level 3)Total
(in millions)
Cash$21 $— $— $21 $7 $— $— $7 
Corporate bonds:   
Investment grade or above— 469 — 469 — 467 — 467 
Equity securities:     
U.S. companies30 — — 30 29 — — 29 
Cash received as collateral from securities lending94 — — 94 47 — — 47 
U.S. treasuries and government agencies178 — — 178 163 — — 163 
Mortgage backed securities— 15 — 15 — 6 — 6 
Asset backed securities— 1 — 1 — 2 — 2 
Municipal bonds— 25 — 25 — 24 — 24 
International government bonds— 9 — 9 — 10 — 10 
Obligation to return cash received as collateral from securities lending(94)— — (94)(47)— — (47)
Financial instruments— (4)— (4)— — — — 
Total investments at fair value$229 $515 $— 744 $199 $509 $— 708 
Investments measured by net asset value per share or its equivalent (1) (2)
460 504 
Total Investments$1,204 $1,212 
 Fair Value Measurements as of December 31, 2017
 
Quoted Prices in
Active Markets for
Identical Assets
(Level 1)
 
Significant
Observable Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3) (3)
 Total
 (in millions)
Cash$18
 $—
 $—
 $18
Corporate bonds: 
  
  
  
Investment grade or above—
 432
 —
 432
Equity securities: 
  
  
  
U.S. companies76
 —
 —
 76
Cash received as collateral from securities lending76
 —
 —
 76
U.S. treasuries67
 —
 —
 67
Mortgage backed securities—
 8
 —
 8
Asset backed securities—
 1
 —
 1
Municipal bonds—
 47
 —
 47
Mutual funds (1)
211
 —
 —
 211
International government bonds—
 17
 —
 17
Obligation to return cash received as collateral from securities lending(76) —
 —
 (76)
Total investments at fair value$372
 $505
 $—
 $877
Investments measured by net asset value per share or its equivalent (2)
      924
Total Investments      $1,801


(1)
57% of the amount invested in mutual funds was in international equities, 30% was in emerging market equities and 13% was in U.S. equities.

(2)This represents the common collective trust funds with 55% of the amount invested in fixed income securities, 6% in U.S. equities, 34% in international equities and 5% in emerging market equities.

(3)The changes in the fair value of the pension plan’s Level 3 investments for the year ended December 31, 2017 were not material.

(1)Represents investments in pooled investment funds and common collective trust funds.

(2)The amounts invested in pooled investment funds were 100% allocated to real estate. The amounts invested common collective trust funds were allocated as follows:

As of December 31,
20232022
International equities40 %40 %
U.S. equities59 %56 %
Fixed income1 %4 %


Level 2 investments, which do not have a quoted price in active market, are valued using the market data provided by independent pricing services or major market makers, to arrive ata price a dealer would pay for thesecurity.
 Fair Value Measurements as of December 31, 2016
 
Quoted Prices in
Active Markets for
Identical Assets
(Level 1)
 
Significant
Observable Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3) (3)
 Total
 (in millions)
Cash$14
 $—
 $—
 $14
Corporate bonds: 
  
  
  
Investment grade or above—
 401
 —
 401
Equity securities: 
  
  
  
U.S. companies73
 —
 —
 73
Cash received as collateral from securities lending69
 —
 —
 69
U.S. treasuries49
 —
 —
 49
Mortgage backed securities—
 3
 —
 3
Asset backed securities—
 2
 —
 2
Municipal bonds—
 52
 —
 52
Mutual funds (1)
171
 —
 —
 171
International government bonds—
 16
 —
 16
Obligation to return cash received as collateral from securities lending(69) —
 —
 (69)
Total investments at fair value$307
 $474
 $—
 $781
Investments measured by net asset value per share or its equivalent (2)
      875
Total Investments      $1,656


(1)
57% of the amount invested in mutual funds was in international equities, 28% was in emerging market equities and 15% was in U.S. equities.

(2)This represents the common collective trust funds with 53% of the amount invested in fixed income securities, 12% in U.S. equities, 30% in international equities and 5% in emerging market equities.

(3)The changes in the fair value of the pension plan’s Level 3 investments for the year ended December 31, 2016 were not material.

The pension planplans utilized both exchange traded and over-the-counter financial instruments such as futures, interest rate options and swaps that were marked to market daily with the gains/losses settled in the cash accounts. The pension planplans did not include any holdings of CenterPoint Energy common stockCommon Stock as of December 31, 20172023 or 2016.2022.


(f) Postretirement Plan Assets

In managing the investments associated with the postretirement plans, the Registrants’ primary objective is to preserve and improve the funded status of the plan, while minimizing volatility. This objective is expected to be achieved through an investment strategy that manages liquidity requirements while maintaining a long-term horizon in making investment decisions and efficient and effective management of plan assets.

133

As part of the investment strategy discussed above, the Registrants maintained the following weighted-average allocation targets for the postretirement plans as of December 31, 2023:
CenterPoint EnergyHouston ElectricCERC
MinimumMaximumMinimumMaximumMinimumMaximum
U.S. equities14 %24 %13 %23 %15 %25 %
International equities3 %13 %3 %13 %2 %12 %
Fixed income69 %79 %69 %79 %68 %78 %
Cash— %2 %— %2 %— %2 %

The following tables presenttable sets forth by level, within the fair value hierarchy CenterPoint Energy’s(see Note 10), the Registrants’ postretirement plan assets at fair value as of December 31, 20172023 and 2016, by asset category:2022:
Fair Value Measurements as of December 31,
20232022
Mutual Funds
 
(Level 1)
(Level 2)
(Level 3)		Total
(Level 1)
(Level 2)
(Level 3)		Total
(in millions)
CenterPoint Energy$113 $— $— $113 $109 $— $— $109 
Houston Electric86 — — 86 84 — — 84 
CERC26 — — 26 25 — — 25 

The amounts invested in mutual funds were allocated as follows:
As of December 31,
20232022
CenterPoint EnergyHouston ElectricCERCCenterPoint EnergyHouston ElectricCERC
Fixed income72 %72 %71 %74 %74 %74 %
U.S. equities20 %19 %22 %18 %17 %20 %
International equities8 %9 %6 %8 %8 %6 %

(g) Benefit Plan Contributions

The Registrants made the following contributions in 2023 and are required to make the following minimum contributions in 2024 to the indicated benefit plans below:
Contributions in 2023Expected Minimum Contributions in 2024
CenterPoint EnergyHouston ElectricCERCCenterPoint EnergyHouston ElectricCERC
(in millions)
Qualified pension plans$24 $— $— $2 $— $— 
Non-qualified pension plans8 — — 7 — — 
Postretirement benefit plans7 — 4 8 1 4 

134
 Fair Value Measurements as of December 31, 2017
 
Quoted Prices
in Active
Markets for
Identical Assets
(Level 1)
 
Significant
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 Total
 (in millions)
Mutual funds (1)
$120
 $—
 $—
 $120
Total$120
 $—
 $—
 $120

(1)
74% of the amount invested in mutual funds was in fixed income securities, 18% was in U.S. equities and 8% was in international equities.




 Fair Value Measurements as of December 31, 2016
 
Quoted Prices
in Active
Markets for
Identical Assets
(Level 1)
 
Significant
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 Total
 (in millions)
Mutual funds (1)
$113
 $—
 $—
 $113
Total$113
 $—
 $—
 $113

(1)
74% of the amount invested in mutual funds was in fixed income securities, 18% was in U.S. equities and 8% was in international equities.

CenterPoint Energy contributed $39 million, $9 million and $16 million to its qualified pension, non-qualified pension and postretirement benefits plans, respectively, in 2017. CenterPoint Energy expects to contribute a minimum of approximately $60 million, $7 million and $16 million to its qualified pension, non-qualified pension and postretirement benefits plans, respectively, in 2018.

The following benefit payments are expected to be paid by the pension and postretirement benefit plans:
 Pension
Benefits		Postretirement Benefits
CenterPoint
Energy		CenterPoint
Energy		Houston ElectricCERC
(in millions)
2024$141 $14 $6 $5 
2025143 16 6 6 
2026137 17 7 6 
2027135 19 8 7 
2028133 20 9 7 
2029-2033606 107 49 36 
 
Pension
Benefits
 
Postretirement Benefit
Payments
 (in millions)
2018$144
 $19
2019147
 21
2020153
 24
2021156
 27
2022158
 29
2023-2027774
 145


(c)(h) Savings Plan


CenterPoint Energy hasmaintains the CenterPoint Energy Savings Plan, a tax-qualified employee savings plan that includes a cash or deferred arrangement under Section 401(k) of the Internal Revenue Code, of 1986, as amended (the Code), and an employee stock ownership plan under Section 4975(e)(7) of the Code. Under the plan, participating employees may make pre-tax or Roth contributions up to 50%, and, after taxif eligible, after-tax contributions up to 16%, of their eligible compensation, not to exceed certain federally mandated limits. Participating Registrants provide matching contributions and, as of January 1, 2020, for certain eligible employees, non-elective contributions up to certain limits. CenterPoint Energy, matches 100%through the Merger, also acquired additional defined contribution retirement savings plans sponsored by Vectren and its subsidiaries that are qualified under sections 401(a) and 401(k) of the first 6%Code, one of each employee’s compensation contributed. The matching contributions are fully vested at all times.

Prior towhich merged into the CenterPoint Energy Savings Plan as of January 1, 2016, participating employees could elect to invest all or a portion2020 and one of their contributions towhich merged into the plan in CenterPoint Energy Inc. common stock, to have dividends reinvested in additional shares or to receive dividend payments in cash on any investment inSavings Plan as of January 1, 2022. As of January 1, 2022, the CenterPoint Energy Inc. common stock, and to transfer all or part of their investment inSavings Plan is the only remaining qualified defined contribution retirement savings plan maintained by CenterPoint Energy.

The CenterPoint Energy Inc. common stock to other investment options offeredSavings Plan has significant holdings of Common Stock. As of December 31, 2023, 6,589,241 shares of Common Stock were held by the plan.

Effective January 1, 2016, the savings plan, was amendedwhich represented approximately 7% of its investments. Given the concentration of the investments in Common Stock, the savings plan and its participants have market risk related to limitthis investment. The savings plan limits the percentage of future contributions that couldcan be invested in CenterPoint Energy, Inc. common stockCommon Stock to 25% and to prohibitprohibits transfers of account balances where the transfer would result in more than 25% of a participant’s total account balance invested in Common Stock.

CenterPoint Energy Inc. common stock.

The savings plan has significant holdings of CenterPoint Energy, Inc. common stock. As of December 31, 2017, 12,806,085 shares of CenterPoint Energy, Inc. common stock were held byallocates the savings plan which represented approximately 16% of its investments. Given the concentration of the investments in CenterPoint Energy, Inc. common stock, the savings planbenefit expense to Houston Electric and its participants have market riskCERC related to this investment.

CenterPoint Energy’stheir respective employees. The following table summarizes the Registrants’ savings plan benefit expenses were $41 million, $38 millionexpense for 2023, 2022 and $35 million2021:
 Year Ended December 31,
 202320222021
 CenterPoint EnergyHouston ElectricCERCCenterPoint EnergyHouston ElectricCERCCenterPoint EnergyHouston ElectricCERC
 (in millions)
Savings plan benefit
 expenses (1)
$67 $23 $20 $72 $23 $22 $58 $20 $23 

(1)Amounts presented in 2017, 2016the table above are included in Operation and 2015, respectively.maintenance expense in the Registrants’ respective Statements of Consolidated Income and shown prior to any amounts capitalized.



(i) Other Benefits Plans


(d) Postemployment Benefits

The Registrants participate in CenterPoint Energy providesEnergy’s plans that provide postemployment benefits for certain former or inactive employees, their beneficiaries and covered dependents, after employment but before retirement (primarily healthcare and life insurance benefits for participants in the long-term disability plan).

CenterPoint Energy recorded postemployment expenses of $6 million, $5 million and $2 million in 2017, 2016 and 2015, respectively.

Included in Benefit Obligations in the accompanying Consolidated Balance Sheets as of December 31, 2017 and 2016 was $20 million and $22 million, respectively, relating to postemployment obligations.

(e) Other Non-Qualified Plans

CenterPoint Energy hasmaintains non-qualified deferred compensation plans that provide benefits payable to eligible directors, officers and certain keyselect employees or their designated beneficiaries at specified future dates or upon termination, retirement or death. Benefit payments are made from the general assets of CenterPoint Energy. CenterPoint Energythe participating Registrants or, in the case of certain plans, from a rabbi trust that is a grantor trust and remains subject to the claims of general creditors under applicable state and federal law.
135


Expenses related to other benefit plans were recorded as follows:
 Year Ended December 31,
 202320222021
 CenterPoint EnergyHouston ElectricCERCCenterPoint EnergyHouston ElectricCERCCenterPoint EnergyHouston ElectricCERC
 (in millions)
Postemployment benefits$(1)$— $— $4 $1 $1 $3 $1 $2 
Deferred compensation plans(1)— — 1 — — 3 — — 

Amounts related to other benefit expense relating to these plans of $3 million for each of the years in 2017, 2016 and 2015. Includedwere included in Benefit Obligations in the Registrants’ accompanying Consolidated Balance Sheets as of December 31, 2017 and 2016 was $45 million and $47 million, respectively, relating to deferred compensation plans.follows:

 December 31, 2023December 31, 2022
 CenterPoint EnergyHouston ElectricCERCCenterPoint EnergyHouston ElectricCERC
 (in millions)
Postemployment benefits$5 $2 $3 $9 $3 $4 
Deferred compensation plans26 3 1 28 4 1 
Split-dollar life insurance arrangements46 1 — 22 1 — 
Included in Benefit Obligations in CenterPoint Energy’s Consolidated Balance Sheets as of December 31, 2017 and 2016 was $39 million and $40 million, respectively, relating to split-dollar life insurance arrangements.

(f)(j) Change in Control Agreements and Other Employee Matters


CenterPoint Energy has a change in control plan, which was effective Januaryamended and restated on May 1, 2015.2017. The plan generally provides, to the extent applicable, in the case of a change in control of CenterPoint Energy and covered termination of employment, for severance benefits of up to three times annual base salary plus bonus, and other benefits. OurCertain CenterPoint Energy officers including our Executive Chairman, are participants under the plan.


Certain key employees of a subsidiary of Vectren have employment agreements that provide payments and other benefits upon a covered termination of employment.

As of December 31, 2017, approximately 35% of CenterPoint Energy’s2023, the Registrants’ employees were covered by collective bargaining agreements. The collective bargaining agreement with the IBEW Local 66 and the two collective bargaining agreements with Professional Employees International Union Local 12, covering approximately 21% of CenterPoint Energy’s employees, will expire in May of 2020 and March and May of 2021, respectively. These three agreements were last negotiated in 2016.as follows:

Percentage of Employees Covered
 Agreement ExpirationCenterPoint EnergyHouston ElectricCERC
IBEW Local 66May 202617 %53 %— %
OPEIU Local 12December 20252 %— %2 %
Gas Workers Union Local 340April 20255 %— %13 %
IBEW Locals 1393 and USW Locals 12213 & 7441December 20263 %— %8 %
IBEW Locals 949December 20253 %— %7 %
USW Locals 13-227June 20275 %— %13 %
USW Locals 13-1June 2027— %— %1 %
IBEW Local 702June 20253 %— %— %
Teamsters Local 135/215September 2024— %— %— %
UWUA Local 175October 20242 %— %4 %
Total40 %53 %48 %

The collective bargaining agreements with GasTeamsters Local 135 related to SIGECO employees and Utility Workers Union of America, Local 340175 related to VEDO employees are scheduled to expire in September 2024 and October 2024, respectively, and negotiations of these agreements are expected to be completed before the IBEW Local 949, covering approximately 8%respective expirations.

Board of Directors Actions. On July 22, 2021, CenterPoint Energy announced the decision of the independent directors of the Board to implement a new independent Board leadership and governance structure and appointed a new independent chair
136

of the Board. To implement this new governance structure, the independent directors of the Board eliminated the Executive Chairman position that was formerly held by Milton Carroll.

On the approval and recommendation of the Compensation Committee and approval of the Board (acting solely through its independent directors), CenterPoint Energy entered into a separation agreement between CenterPoint Energy and Mr. Carroll, dated July 21, 2021. Under the terms of the separation agreement, Mr. Carroll exited the positions of Executive Chairman on July 21, 2021 and Board member on September 30, 2021.Under the terms of the separation agreement, Mr. Carroll received a lump sum cash payment of $28 million and his separation was treated as an “enhanced retirement” for purposes of his outstanding 2019, 2020 and 2021 equity award agreements.

On the approval and recommendation of the Compensation Committee and approval of the Board (acting solely through its independent directors), CenterPoint Energy has entered into a retention incentive agreement with David J. Lesar, President and Chief Executive Officer of CenterPoint Energy’s employees, will expire in April and DecemberEnergy, dated July 20, 2021. For information about the classification of 2020, respectively. These two agreements were last negotiated in 2015.this award, see Note 12.


(9) Derivative Instruments

The two collective bargaining agreements with the United Steelworkers Union, Locals 13-227 and 13-1, which cover approximately 5% of CenterPoint Energy’s employees, were successfully negotiated in 2017. The new agreements will expire in June and July of 2022 for the Local 13-227 and Local 13-1, respectively.

(8) Derivative Instruments

CenterPoint Energy isRegistrants are exposed to various market risks. These risks arise from transactions entered into in the normal course of business. CenterPoint Energy utilizesThe Registrants, from time to time, utilize derivative instruments such as physical forward contracts, swaps and options to mitigate the impact of changes in commodity prices, weather and interest rates on its operating results and cash flows.


(a) Non-Trading Activities


Commodity Derivative Instruments.Instruments (CenterPoint Energy and CERC). CenterPoint Energy entersand CERC, through the Indiana Utilities they respectively own, enter into certain derivative instruments, including physical forward contracts, to mitigate the effects of commodity price movements. Certain financialOutstanding derivative instruments used todesignated as economic hedges at the Indiana Utilities hedge portions of thelong-term variable rate natural gas inventory ofpurchases. The Indiana Utilities have authority to refund and recover mark-to-market gains and losses associated with hedging natural gas purchases, and thus the Energy Services business segmentgains and losses on derivatives are designated as fair value hedges for accounting purposes.deferred in a regulatory liability or asset. All other financial instruments do not qualify or are not designated as cash flow or fair value hedges. As of both December 31, 2023 and 2022, the notional volumes of both CenterPoint Energy’s and CERC’s natural gas derivatives were 27,421 MMBtu per day.


Weather Hedges. CenterPoint Energy has weather normalizationInterest Rate Risk Derivative Instruments. From time to time, the Registrants may enter into interest rate derivatives that are designated as economic or cash flow hedges. The objective of these hedges is to offset risk associated with interest rates borne by the Registrants in connection with an anticipated future fixed rate debt offering or other exposure to variable rate mechanisms that mitigate the impact of weather on NGD in Arkansas, Louisiana, Mississippi, Minnesota and Oklahoma. NGD and electric operations in Texas do not have such mechanisms, although fixed customer charges are historically higher in Texas for NGD compared to CenterPoint Energy’s other


jurisdictions. As a result, fluctuations from normal weather may have a positive or negative effect on NGD’s results in Texas and on Houston Electric’s results in its service territory.

CenterPoint Energy entered into heating-degree day swaps for certain NGD jurisdictions to mitigate the effect of fluctuations from normal weather on its results of operations and cash flows for the 2014-2015 winter heating season, which contained a bilateral dollar cap of $16 million. However, CenterPoint Energy did not enter into heating-degree day swaps for NGD jurisdictions for the 2015–2016 or 2016–2017 winter heating seasons. CenterPoint Energy entered into heating-degree day swaps for certain NGD Texas jurisdictions for the 2017–2018 winter heating season, which contained a bilateral dollar cap of $8 million. CenterPoint Energy entered into weather hedges for thedebt. Houston Electric service territoryand the Indiana Utilities have authority to mitigate the effect of fluctuations from normal weather on its results of operationsrefund and cash flows, which contained bilateral dollar caps of $7 million, $9 million and $9 million for the 2015–2016, 2016–2017 and 2017–2018 winter seasons, respectively. The swaps are based on 10-year normal weather. During the years ended December 31, 2017, 2016 and 2015, CenterPoint Energy recognized a loss of $1 million, gain of $1 million and a loss of $6 million, respectively, related to these swaps.   Weather hedgerecover mark-to-market gains and losses associated with hedging financing activity, and thus the gains and losses on derivatives are includeddeferred in revenues ina regulatory liability or asset. For the Statementsimpacts of Consolidated Income.cash flow hedges to Accumulated other comprehensive income, see Note 12.


Hedging of Interest Expense for Future Debt Issuances. In January 2017,The table below summarizes CenterPoint Energy’s and Houston Electric entered into forwardElectric’s outstanding interest rate agreements with multiple counterparties, having an aggregate notional amount of $150 million. These agreements were executed to hedge, in part, volatility in the 10-year U.S. treasury rate by reducing Houston Electric’s exposure to variability in cash flows relatedhedging activity:
December 31, 2023December 31, 2022
Hedging ClassificationNotional Principal
(in millions)
CenterPoint Energy:
Economic hedge (1)
$— $84 
Cash flow hedge (2) (3)
200 — 
Houston Electric:
Cash flow hedge (3)
100 — 

(1)Relates to interest paymentsrate derivative instruments at SIGECO that terminated on May 1, 2023.
(2)Relates to interest rate derivative instruments at CenterPoint Energy with a termination date of Houston Electric’s $300 million issuance of fixedDecember 31, 2029. The interest rate debt in January 2017. These forward interest rateswap agreements were designated as cash flow hedges. Accordingly,hedges of forecasted transactions. CenterPoint Energy records all changes in the effective portionfair value of realized losses associated with the agreements, which totaled approximately $1 million, is a component ofcash flow hedges in accumulated other comprehensive income (loss) until the underlying hedged transaction occurs, when it reclassifies that amount into earnings.
(3)Relates to interest rate derivative instruments at Houston Electric with a termination date of June 28, 2024. The interest rate treasury lock agreements were designated as cash flow hedges of forecasted transactions. Houston Electric records
137

all changes in 2017 and will bethe fair value of cash flow hedges to a regulatory asset or liability, which is amortized over the life of the bonds.associated debt being hedged.

In 2017, CenterPoint Energy entered into forward interest rate agreements with multiple counterparties, having an aggregate notional amount of $350 million. These agreements were executed to hedge, in part, volatility in the 5-year U.S. treasury rate by reducing CenterPoint Energy’s exposure to variability in cash flows relating to interest payments of CenterPoint Energy’s $500 million issuance of fixed rate debt in August 2017. These forward interest rate agreements were designated as cash flow hedges. Accordingly, the effective portion of realized losses associated with the agreements, which totaled approximately $3 million, is a component of accumulated other comprehensive income in 2017 and will be amortized over the life of the fixed rate debt.

In August 2017, CERC Corp. entered into forward interest rate agreements with multiple counterparties, having an aggregate notional amount of $150 million. These agreements were executed to hedge, in part, volatility in the 30-year U.S. treasury rate by reducing CERC Corp.’s exposure to variability in cash flows related to interest payments of CERC Corp.’s $300 million issuance of fixed rate debt in August 2017. These forward interest rate agreements were designated as cash flow hedges. Accordingly, the effective portion of realized losses associated with the agreements, which totaled approximately $2 million, is a component of accumulated other comprehensive income in 2017 and will be amortized over the life of the fixed rate debt.

As of December 31, 2017, none of CenterPoint Energy, Houston Electric or CERC Corp. had any pre-issuance interest rate hedges in place.

In January and February 2018, Houston Electric entered into forward interest rate agreements with multiple counterparties, having an aggregate notional amount of $200 million. These agreements were executed to hedge, in part, volatility in the 30-year U.S. treasury rate by reducing Houston Electric’s exposure to variability in cash flows related to interest payments on a forecasted issuance of fixed rate debt in 2018. These forward interest rate agreements were designated as cash flow hedges. Accordingly, the effective portion of unrealized gains and losses associated with the forward interest rate agreements will be recorded as a component of accumulated other comprehensive income and the ineffective portion, if any, will be recorded in income.





(b) Derivative Fair Values and Income Statement Impacts


CenterPoint Energy’s outstanding interest rate derivatives designated as cash flow hedges described above were not material as of December 31, 2023 and are included in current non-trading derivative liabilities on CenterPoint Energy’s Consolidated Balance Sheets. Houston Electric’s outstanding interest rate derivatives designated as cash flow hedges described above were not material as of December 31, 2023 and are included in prepaid expenses and other current assets on Houston Electric’s Consolidated Balance Sheets.

The following tables present information about CenterPoint Energy’s derivative instruments and hedging activities. The first four tablesbelow provide a balance sheet overview of CenterPoint Energy’s Derivative Assets and LiabilitiesCERC’s derivative assets and liabilities as of December 31, 20172023 and 2016, while2022.

December 31, 2023December 31, 2022
Balance Sheet LocationDerivative
Assets
Fair Value		Derivative
Liabilities
Fair Value		Derivative
Assets
Fair Value		Derivative
Liabilities
Fair Value
CenterPoint Energy:(in millions)
Derivatives not designated as hedging instruments:
Natural gas derivatives (1)
Current Assets: Non-trading derivative assets$— $— $9 $— 
Interest rate derivativesCurrent Assets: Non-trading derivative assets— — 1 — 
Natural gas derivatives (1)
Other Assets: Non-trading derivative assets— — 2 — 
Natural gas derivatives (1)
Current Liabilities: Non-trading derivative liabilities— 9 — — 
Natural gas derivatives (1)
Other Liabilities: Non-trading derivative liabilities— 3 — — 
Indexed debt securities derivative (2)
Current Liabilities— 605 — 578 
Total$— $617 $12 $578 

(1)Natural gas contracts are subject to master netting arrangements. This netting applies to all undisputed amounts due or past due. However, the lastmark-to-market fair value of each natural gas contract is in a liability or asset position with no offsetting amount as of December 31, 2023 and 2022, respectively.
(2)Derivative component of the ZENS obligation that represents the ZENS holder’s option to receive the appreciated value of the reference shares at maturity and other payments to which they may be entitled. See Note 11 for further information.

December 31, 2023December 31, 2022
Balance Sheet LocationDerivative
Assets
Fair Value		Derivative Liabilities
Fair Value		Derivative
Assets
Fair Value		Derivative Liabilities
Fair Value
CERC:(in millions)
Derivatives not designated as hedging instruments:
Natural gas derivatives (1)
Current Assets: Non-trading derivative assets$— $— $7 $— 
Natural gas derivatives (1)
Other Assets: Non-trading derivative assets— — 2 — 
Natural gas derivatives (1)
Current Liabilities: Non-trading derivative liabilities— 8 — — 
Natural gas derivatives (1)
Other Liabilities: Non-trading derivative liabilities— 3 — — 
Total$— $11 $9 $— 

(1)Natural gas contracts are subject to master netting arrangements. This netting applies to all undisputed amounts due or past due. However, the mark-to-market fair value of each natural gas contract is in a liability or asset position with no offsetting amount as of December 31, 2023 and 2022, respectively.
138


The table below provides a breakdown of the related income statement impacts of derivative activity for the years ending December 31, 2017, 20162023, 2022 and 2015.2021.
Year Ended December 31,
Income Statement Location202320222021
CenterPoint Energy:(in millions)
Effects of derivatives not designated as hedging instruments:
Indexed debt securities derivative (1)
Gain (loss) on indexed debt securities$(27)$325 $50 
Total CenterPoint Energy$(27)$325 $50 
Fair Value of Derivative Instruments
  December 31, 2017
Derivatives designated
as fair value hedges:
 
Balance Sheet
Location
 
Derivative
Assets
Fair Value
 
Derivative
Liabilities
Fair Value
    (in millions)
Natural gas derivatives (1) (2) (3)
 Current Liabilities: Non-trading derivative liabilities $13
 $1
       
Derivatives not designated as hedging instruments:      
Natural gas derivatives (1) (2) (3)
 Current Assets: Non-trading derivative assets 114
 4
Natural gas derivatives (1) (2) (3)
 Other Assets: Non-trading derivative assets 44
 —
Natural gas derivatives (1) (2) (3)
 Current Liabilities: Non-trading derivative liabilities 38
 78
Natural gas derivatives (1) (2) (3)
 Other Liabilities: Non-trading derivative liabilities 9
 24
Indexed debt securities derivative Current Liabilities —
 668
Total $218
 $775


(1)The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling 1,795 Bcf or a net 224 Bcf long position.  Certain natural gas contracts hedge basis risk only and lack a fixed price exposure.

(2)Natural gas contracts are presented on a net basis(1)The indexed debt securities derivative is recorded at fair value and changes in the fair value are recorded in the Consolidated Balance Sheets as they are subject to master netting arrangements. This netting applies to all undisputed amounts due or past due and causes derivative assets (liabilities) to be ultimately presented net in a liability (asset) account within the Consolidated Balance Sheets. The net of total non-trading natural gas derivative assets and liabilities was a $130 million asset as shown on CenterPoint Energy’s Consolidated Balance Sheets (and as detailed in the table below), and was comprised of the natural gas contracts derivative assets and liabilities separately shown above, impacted by collateral netting of $19 million.

(3)Derivative Assets and Derivative Liabilities include no material amounts related to physical forward transactions with Enable.
Offsetting of Natural Gas Derivative Assets and Liabilities
  December 31, 2017
  
Gross Amounts Recognized (1)
 Gross Amounts Offset in the Consolidated Balance Sheets Net Amount Presented in the Consolidated Balance Sheets (2)
  (in millions)
Current Assets: Non-trading derivative assets $165
 $(55) $110
Other Assets: Non-trading derivative assets 53
 (9) 44
Current Liabilities: Non-trading derivative liabilities (83) 63
 (20)
Other Liabilities: Non-trading derivative liabilities (24) 20
 (4)
Total $111
 $19
 $130

(1)Gross amounts recognized include some derivative assets and liabilities that are not subject to master netting arrangements.

(2)The derivative assets and liabilities on the Consolidated Balance Sheets exclude accounts receivable or accounts payable that, should they exist, could be used as offsets to these balances in the event of a default.


Fair Value of Derivative Instruments
  December 31, 2016
Total derivatives not designated
as hedging instruments
 
Balance Sheet
Location
 
Derivative
Assets
Fair Value
 
Derivative
Liabilities
Fair Value
    (in millions)
Natural gas derivatives (1) (2) (3)
 Current Assets: Non-trading derivative assets $79
 $14
Natural gas derivatives (1) (2) (3)
 Other Assets: Non-trading derivative assets 24
 5
Natural gas derivatives (1) (2) (3)
 Current Liabilities: Non-trading derivative liabilities 2
 43
Natural gas derivatives (1) (2) (3)
 Other Liabilities: Non-trading derivative liabilities —
 5
Indexed debt securities derivative Current Liabilities —
 717
Total $105
 $784

(1)The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling 1,035 Bcf or a net 59 Bcf long position.  Certain natural gas contracts hedge basis risk only and lack a fixed price exposure.

(2)
Natural gas contracts are presented on a net basis in the Consolidated Balance Sheets. Natural gas contracts are subject to master netting arrangements. This netting applies to all undisputed amounts due or past due and causes derivative assets (liabilities) to be ultimately presented net in a liability (asset) account within the Consolidated Balance Sheets. The net of total non-trading derivative assets and liabilities was a $24 million asset as shown on CenterPoint Energy’s Consolidated Balance Sheets (and as detailed in the table below), and was comprised of the natural gas contracts derivative assets and liabilities separately shown above, impacted by collateral netting of $14 million.

(3)Derivative Assets and Derivative Liabilities include no material amounts related to physical forward transactions with Enable.
Offsetting of Natural Gas Derivative Assets and Liabilities
  December 31, 2016
  
Gross Amounts Recognized (1)
 Gross Amounts Offset in the Consolidated Balance Sheets Net Amount Presented in the Consolidated Balance Sheets (2)
  (in millions)
Current Assets: Non-trading derivative assets $81
 $(30) $51
Other Assets: Non-trading derivative assets 24
 (5) 19
Current Liabilities: Non-trading derivative liabilities (57) 16
 (41)
Other Liabilities: Non-trading derivative liabilities (10) 5
 (5)
Total $38
 $(14) $24

(1)Gross amounts recognized include some derivative assets and liabilities that are not subject to master netting arrangements.

(2)The derivative assets and liabilities on the Consolidated Balance Sheets exclude accounts receivable or accounts payable that, should they exist, could be used as offsets to these balances in the event of a default.

Realized and unrealized gains and losses on natural gas derivatives are recognized in the Statements of Consolidated Income as revenue for physical sales derivative contracts and as natural gas expense for financial natural gas derivatives and physical purchase natural gas derivatives. Realized and unrealized gains and losses on indexed debt securities are recorded as Other Income (Expense) in the Statements of Consolidated Income.

Hedge ineffectiveness is recorded as a component of natural gas expense and primarily results from differences in the location of the derivative instrument and the hedged item. Basis ineffectiveness arises from natural gas market price differences between the locations of the hedged inventory and the delivery location specified in the hedge instruments. The impact of natural gas derivatives designated as fair value hedges, the related hedged item, and natural gas derivatives not designated as hedging instruments are presented in the table below.




Income Statement Impact of Derivative Activity
    Year Ended December 31,
  Income Statement Location 2017 2016 2015
Derivatives designated as fair value hedges:   (in millions)
Natural gas derivatives Gains (Losses) in Expenses: Natural Gas $(9) $—
 $—
Fair value adjustments for natural gas inventory designated as the hedged item Gains (Losses) in Expenses: Natural Gas 14
 —
 —
Total increase in Expenses: Natural Gas (1)
 $5
 $—
 $—
         
Derivatives not designated as hedging instruments:        
Natural gas derivatives Gains (Losses) in Revenues $211
 $(18) $134
Natural gas derivatives Gains (Losses) in Expenses: Natural Gas (72) 70
 (105)
Indexed debt securities derivative Gains (Losses) in Other Income (Expense) 49
 (413) 74
Total - derivatives not designated as hedging instruments $188
 $(361)
$103

(1)Hedge ineffectiveness results from the basis ineffectiveness discussed above, and excludes the impact to natural gas expense from timing ineffectiveness.  Timing ineffectiveness arises due to changes in the difference between the spot price and the futures price, as well as the difference between the timing of the settlement of the futures and the valuation of the underlying physical commodity.  As the commodity contract nears the settlement date, spot-to-forward price differences should converge, which should reduce or eliminate the impact of this ineffectiveness on natural gas expense.


(c) Credit Risk Contingent Features (CenterPoint Energy and CERC)


Certain of CenterPoint Energy enters into financialEnergy’s and CERC’s derivative contracts containing material adverse change provisions.  Theseinstruments contain provisions couldthat require CenterPoint Energy and CERC to post additional collateral if themaintain an investment grade credit rating on their respective long-term unsecured unsubordinated debt from S&P and Moody’s. If CenterPoint Energy’s or Moody’s credit ratingsCERC’s debt were to fall below investment grade, it would be in violation of CenterPoint Energy, Inc. or its subsidiaries are downgraded.  The total fair value ofthese provisions, and the counterparties to the derivative instruments that contain credit risk contingent features that are in a net liability position as of December 31, 2017 and 2016 was $2 million and $1 million, respectively.  CenterPoint Energy posted no assets as collateral towards derivative instruments that contain credit risk contingent features as of either December 31, 2017could request immediate payment or 2016.  If all derivative contracts (in a net liability position) containing credit risk contingent features were triggered at December 31, 2017 and 2016, $2 million and $-0-, respectively, of additional assets would be required to be posted as collateral.

December 31, 2023December 31, 2022
CenterPoint EnergyCERCCenterPoint EnergyCERC
(in millions)
Aggregate fair value of derivatives containing material adverse change provisions in a net liability position$9 $8 $— $— 
Fair value of collateral already posted— — — — 
Additional collateral required to be posted if credit risk contingent features triggered9 8 — — 
(d) Credit Quality of Counterparties

In addition to the risk associated with price movements, credit risk is also inherent in CenterPoint Energy’s non-trading derivative activities. Credit risk relates to the risk of loss resulting from non-performance of contractual obligations by a counterparty. The following table shows the composition of counterparties to the non-trading derivative assets of CenterPoint Energy as of December 31, 2017 and 2016:
 December 31, 2017 December 31, 2016 
 
Investment
Grade (1)
 Total 
Investment
Grade (1)
 Total 
 (in millions) 
Energy marketers$6
 $45
 $1
 $4
 
Financial institutions—
 —
 33
 33
 
End users (2)
17
 109
 2
 47
 
Total$23
 $154
(3)$36
 $84
(3)

(1)“Investment grade” is primarily determined using publicly available credit ratings and considers credit support (including parent company guarantees) and collateral (including cash and standby letters of credit). For unrated counterparties, CenterPoint Energy determines a synthetic credit rating by performing financial statement analysis and considers contractual rights and restrictions and collateral.

(2)End users are comprised primarily of customers who have contracted to fix the price of a portion of their physical gas requirements for future periods.



(3)The net of total non-trading natural gas derivative assets was $154 million and $70 million as of December 31, 2017 and 2016, respectively, as shown on CenterPoint Energy’s Consolidated Balance Sheets, and was comprised of the natural gas contracts derivatives assets separately shown above, impacted by collateral netting of $-0- and $14 million as of December 31, 2017 and 2016, respectively.

(9)(10) Fair Value Measurements


Assets and liabilities that are recorded at fair value in the Registrants’ Consolidated Balance Sheets are categorized based upon the level of judgment associated with the inputs used to measure their value. Hierarchical levels, as defined below and directly related to the amount of subjectivity associated with the inputs to fair valuations of these assets and liabilities, are as follows:


Level 1: Inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date. The types of assets carried at Level 1 fair value generally are exchange-traded derivatives and equity securities, as well as natural gas inventory that has been designated as the hedged item in a fair value hedge.securities.


Level 2: Inputs, other than quoted prices included in Level 1, are observable for the asset or liability, either directly or indirectly. Level 2 inputs include quoted prices for similar instruments in active markets, and inputs other than quoted prices that are observable for the asset or liability. Fair value assets and liabilities that are generally included in this category are derivatives with fair values based on inputs from actively quoted markets. A market approach is utilized to value the Registrants’ Level 2 natural gas derivative assets or liabilities. CenterPoint Energy’s Level 2 assets or liabilities.indexed debt securities derivative is valued using an option model and a discounted cash flow model, which uses projected dividends on the ZENS-Related Securities and a discount rate as observable inputs.


Level 3: Inputs are unobservable for the asset or liability, and include situations where there is little, if any, market activity for the asset or liability. Unobservable inputs reflect CenterPoint Energy’sthe Registrants’ judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. CenterPoint Energy developsThe Registrants develop these inputs based on the best information available, including CenterPoint Energy’sthe Registrants’ own data. A market approach is utilized to value CenterPoint Energy’s Level 3 assets or liabilities. As of December 31, 2017, CenterPoint Energy’s Level 3 assets and liabilities are comprised of physical natural gas forward contracts and options and its indexed debt securities. Level 3 physical natural gas forward contracts are valued using a discounted cash flow model which includes illiquid forward price curve locations (ranging from $1.73 to $9.02 per MMBtu) as an unobservable input. Level 3 options are valued through Black-Scholes (including forward start) option models which include option volatilities (ranging from 0% to 83%) as an unobservable input.  CenterPoint Energy’s Level 3 physical natural gas forward contracts and options derivative assets and liabilities consist of both long and short positions (forwards and options) and their fair value is sensitive to forward prices and volatilities. If forward prices decrease, CenterPoint Energy’s long forwards lose value whereas its short forwards gain in value.  If volatility decreases, CenterPoint Energy’s long options lose value whereas its short options gain in value. CenterPoint Energy’s Level 3 indexed debt securities are valued using a Black-Scholes option model and a discounted cash flow model, which use option volatility (17%) and a projected dividend growth rate (7%) as unobservable inputs. An increase in either volatilities or projected dividends will increase the value of the indexed debt securities, and a decrease in either the volatilities or projected dividends will decrease the value of the indexed debt securities.


CenterPoint Energy determinesThe Registrants determine the appropriate level for each financial asset and liability on a quarterly basis and recognizesrecognize transfers between levels at the end of the reporting period.  For the year ended December 31, 2017, there were no transfers between Level 1 and 2. CenterPoint Energy also recognizes purchases of Level 3 financial assets and liabilities at their fair market value at the end of the reporting period.



139


The following tables present information about CenterPoint Energy’sthe Registrants’ assets and liabilities (including derivatives that are presented net) measured at fair value on a recurring basis as of December 31, 20172023 and December 31, 2016,2022, and indicate the fair value hierarchy of the valuation techniques utilized by CenterPoint Energythe Registrants to determine such fair value.

 December 31, 2017
 
Quoted Prices in
Active Markets
for Identical Assets
(Level 1)
 
Significant Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 
Netting
Adjustments (1)
 Balance
     
 (in millions)
Assets         
Corporate equities$963
 $—
 $—
 $—
 $963
Investments, including money
market funds (2)
68
 —
 —
 —
 68
Natural gas derivatives (3)
—
 161
 57
 (64) 154
Hedged portion of natural gas inventory14
 —
 —
 —
 14
Total assets$1,045
 $161
 $57
 $(64) $1,199
Liabilities 
  
  
  
  
Indexed debt securities derivative$—
 $—
 $668
 $—
 $668
Natural gas derivatives (3)
—
 96
 11
 (83) 24
Total liabilities$—
 $96
 $679
 $(83) $692
CenterPoint Energy

(1)Amounts represent the impact of legally enforceable master netting arrangements that allow CenterPoint Energy to settle positive and negative positions and also include cash collateral of $19 million posted with the same counterparties.

(2)Amounts are included in Prepaid and Other Current Assets and Other Assets in the Consolidated Balance Sheets.

(3)Natural gas derivatives include no material amounts related to physical forward transactions with Enable.

December 31, 2023December 31, 2022

Level 1		Level 2Level 3Total
Level 1		Level 2Level 3Total
Assets(in millions)
Equity securities$541 $— $— $541 $510 $— $— $510 
Investments, including money market funds (1)
31 — — 31 32 — — 32 
Interest rate derivatives— — — — — 1 — 1 
Natural gas derivatives— — — — — 11 — 11 
Total assets$572 $— $— $572 $542 $12 $— $554 
Liabilities    
Indexed debt securities derivative$— $605 $— $605 $— $578 $— $578 
Natural gas derivatives— 12 — 12 — — — — 
Total liabilities$— $617 $— $617 $— $578 $— $578 

 December 31, 2016
 
Quoted Prices in
Active Markets
for Identical Assets
(Level 1)
 
Significant Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 
Netting
Adjustments (1)
 Balance
 (in millions)
Assets         
Corporate equities$956
 $—
 $—
 $—
 $956
Investments, including money
market funds (2)
77
 —
 —
 —
 77
Natural gas derivatives (3)
11
 74
 20
 (35) 70
Total assets$1,044
 $74
 $20
 $(35) $1,103
Liabilities 
  
  
  
  
Indexed debt securities derivative$—
 $—
 $717
 $—
 $717
Natural gas derivatives (3)
4
 56
 7
 (21) 46
Total liabilities$4
 $56
 $724
 $(21) $763
Houston Electric

(1)Amounts represent the impact of legally enforceable master netting arrangements that allow CenterPoint Energy to settle positive and negative positions and also include cash collateral of $14 million held by CES from the same counterparties.

(2)Amounts are included in Prepaid and Other Current Assets and Other Assets in the Consolidated Balance Sheets.

(3)Natural gas derivatives include no material amounts related to physical forward transactions with Enable.

December 31, 2023December 31, 2022

Level 1		Level 2Level 3Total
Level 1		Level 2Level 3Total
Assets(in millions)
Investments, including money market funds (1)
$14 $— $— $14 $17 $— $— $17 
Total assets$14 $— $— $14 $17 $— $— $17 



CERC
The following table presents additional information about
December 31, 2023December 31, 2022

Level 1		Level 2Level 3Total
Level 1		Level 2Level 3Total
Assets(in millions)
Investments, including money market funds (1)
$15 $— $— $15 $14 $— $— $14 
Natural gas derivatives— — — — — 9 — 9 
Total assets$15 $— $— $15 $14 $9 $— $23 
Liabilities    
Natural gas derivatives$— $11 $— $11 $— $— $— $— 
Total liabilities$— $11 $— $11 $— $— $— $— 

(1)Amounts are included in Prepaid expenses and other current assets in the respective Consolidated Balance Sheets.

During 2023 and 2022, CenterPoint Energy did not have any assets or liabilities including derivatives that are measured at fair value on a recurring basis for which CenterPoint Energy has utilizeddesignated as Level 3 inputs to determine fair value:3.
 
Fair Value Measurements Using Significant
Unobservable Inputs (Level 3)
 Derivative assets and liabilities, net
 Year Ended December 31,
 2017 2016 2015
 (in millions)
Beginning balance$(704) $12
 $17
Purchases (1)
—
 12
 —
Total gains96
 12
 7
Total settlements(11) (27) (12)
Transfers out of Level 3(17) (1) (1)
Transfers into Level 314
 (712) 1
Ending balance (2)
$(622) $(704) $12
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the reporting date (3)
$87
 $(402) $6

(1)Mark-to-market value of Level 3 derivative assets acquired through the purchase of AEM was less than $1 million at the acquisition date.

(2)CenterPoint Energy did not have significant Level 3 sales during any of the years ended December 31, 2017, 2016 or 2015.

(3)During 2016, CenterPoint Energy transferred its indexed debt securities from Level 2 to Level 3 to reflect changes in the significance of the unobservable inputs used in the valuation. As of December 31, 2017, the indexed debt securities liability was $668 million. During the year ended December 31, 2017, there was a gain of $49 million on the indexed debt securities.


Items Measured at Fair Value on a Nonrecurring Basis


In 2015, CenterPoint Energy determined that an other than temporary decrease in the value of its investment in Enable had occurred and, using multiple valuation methodologies under both the market and income approaches, recorded an impairment on its investment in Enable of $1,225 million. Key assumptions in the market approach included recent market transactions of comparable companies and EBITDA to total enterprise multiples for comparable companies. Due to volatility of the quoted price of Enable’s units at the valuation date,For a volume weighted average price was used under the market approach to best approximate fair value at the measurement date. Key assumptions in the income approach included Enable’s forecasted cash distributions, projected cash flows of incentive distribution rights, forecasted growth rate of Enable’s cash distributions beyond 2020, and the discount rate used to determine the present value of the estimated future cash flows. A weighing of the different approaches was utilized to determine the estimated fair value of our investment in Enable. Based on the significant unobservable estimates and assumptions required, CenterPoint Energy concluded that the fair value estimate should be classified as a Level 3 measurement within the fair value hierarchy. See Note 10 for further discussion of the impairments. Asvaluation of December 31, 2017the Arkansas and 2016, there were no significant assets or liabilities measured at fair value on a nonrecurring basis.Oklahoma Natural Gas businesses in 2021, see Note 4.




Estimated Fair Value of Financial Instruments


The fair values of cash and cash equivalents, investments in debt and equity securities classified as “trading” and short-term borrowings are estimated to be approximately equivalent to carrying amounts and have been excluded from the table below. The carrying amounts of non-trading derivative assets and liabilities and CenterPoint Energy’s equity securities, including ZENS indexed debt securitiesrelated derivative liabilities, are stated at fair value and are excluded from the table below. The fair value of each debt instrument is determined by multiplying the principal amount of each debt instrument by a combination of historical
140

trading prices and comparable issue data. These liabilities, which are not measured at fair value in the Registrants’ Consolidated Balance Sheets, but for which the fair value is disclosed, would be classified as Level 2 in the fair value hierarchy.
 December 31, 2023December 31, 2022
 
CenterPoint Energy (1)
Houston Electric (1)
CERC
CenterPoint Energy (1)
Houston Electric (1)
CERC
Long-term debt, including current maturities(in millions)
Carrying amount$18,609 $7,587 $4,670 $16,338 $6,353 $4,826 
Fair value17,804 6,917 4,627 14,990 5,504 4,637 

(1)Includes Securitization Bond debt.

(11) Equity Securities and Indexed Debt Securities (ZENS) (CenterPoint Energy)
 December 31, 2017 December 31, 2016
 
Carrying
Amount
 
Fair
Value
 
Carrying
Amount
 
Fair
Value
 (in millions)
Financial liabilities:       
Long-term debt$8,679
 $9,220
 $8,443
 $8,846


(a) Equity Securities

(10) Unconsolidated AffiliatesGains and losses on equity securities, net of transaction costs, are recorded as Gain (loss) on equity securities in CenterPoint Energy’s Statements of Consolidated Income. The following table presents information on CenterPoint Energy's equity securities for each period indicated:


Year Ended December 31,
202320222021
(in millions)
AT&T Common$(17)$(63)$(43)
Charter Common43 (273)(8)
WBD Common5 23 — 
Energy Transfer Common Units (1)
— 95 (124)
Energy Transfer Series G Preferred Units (1)
— (9)2 
Other— — 1 
Total Gains (Losses) on Equity Securities$31 $(227)$(172)
(1)In 2022, CenterPoint Energy completed the execution of its previously announced plan to exit the midstream sector by selling the remaining Energy Transfer Common Units and Energy Transfer Series G Preferred Units it held.

CenterPoint Energy hasrecorded unrealized gains (losses) of $31 million, $(313) million, and $(52) million for the ability to significantly influence the operatingyears ended December 31, 2023, 2022, and financial policies of Enable, a publicly traded MLP, and, accordingly, accounts2021, respectively, for its investment in Enable’s common units using the equity method of accounting for in-substance real estate. See Note 2 for information on the formation of Enable.

CenterPoint Energy’s maximum exposure to loss related to Enable, a VIE in which CenterPoint Energy is not the primary beneficiary, is limited to its equity investment and Series A Preferred Unit investment as presented in the Consolidated Balance Sheetsecurities held as of December 31, 20172023, 2022, and outstanding current accounts receivable from Enable.2021.


Limited Partner Interest in Enable (1):
  As of December 31,
  2017 2016 (2) 2015
CenterPoint Energy 54.1% 54.1% 55.4%
OGE 25.7% 25.7% 26.3%

(1)Excluding the Series A Preferred Units owned by CenterPoint Energy.

(2)In November 2016, Enable completed a public offering of 11,500,000 common units of which 1,424,281 were sold by ArcLight Capital Partners, LLC. The common units issued and sold by Enable resulted in dilution of both CenterPoint Energy’s and OGE’s limited partner interest in Enable.

Enable Common Units and Series A Preferred Units Held:
 December 31, 2017
 Common Series A Preferred 
CenterPoint Energy233,856,623
(1)14,520,000
(2)
OGE110,982,805
 —
 

(1)The 139,704,916 subordinated units previously owned by CERC Corp. converted into common units of Enable on a one-for-one basis, on August 30, 2017, at the end of the subordination period, as set forth in Enable’s Fourth Amended and Restated Agreement of Limited Partnership. Upon conversion, holders of common units resulting from the conversion of subordinated units have all the rights and obligations of unitholders holding all other common units, including the right to receive distributions pro rata made with respect to common units.

(2)On February 18, 2016, CenterPoint Energy purchased an aggregate of 14,520,000 Series A Preferred Units from Enable for a total purchase price of $363 million, which is accounted for as a cost method investment.



Generally, sales of more than 5% of the aggregate of the common units CenterPoint Energy owns in Enable or sales by OGE of more than 5% of the aggregate of the common units it owns in Enable are subject to mutual rights of first offer and first refusal.

Enable is controlled jointly by CERC Corp. and OGE, and each own 50% of the management rights in the general partner of Enable. Sale of CenterPoint Energy’s or OGE’s ownership interests in Enable’s general partner to a third party is subject to mutual rights of first offer and first refusal, and CenterPoint Energy is not permitted to dispose of less than all of its interest in Enable’s general partner.

Distributions Received from Enable:
  Year Ended December 31,
  2017 2016 2015
  (in millions)
Investment in Enable’s common units $297
 $297
 $294
Investment in Enable’s Series A Preferred Units 36
 22
(1)—
  Total $333
 $319
 $294
(1)Represents the period from February 18, 2016 to December 31, 2016.

As of December 31, 2017, CERC Corp. and OGE also owned 40% and 60%, respectively, of the incentive distribution rights held by the general partner of Enable. Enable is expected to pay a minimum quarterly distribution of $0.2875 per common unit on its outstanding common units to the extent it has sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to its general partner and its affiliates, within 60 days after the end of each quarter. If cash distributions to Enable’s unitholders exceed $0.330625 per common unit in any quarter, the general partner will receive increasing percentages or incentive distributions rights, up to 50%, of the cash Enable distributes in excess of that amount. In certain circumstances the general partner of Enable will have the right to reset the minimum quarterly distribution and the target distribution levels at which the incentive distributions receive increasing percentages to higher levels based on Enable’s cash distributions at the time of the exercise of this reset election. To date, no incentive distributions have been made.

Effective on the formation date, CenterPoint Energy and Enable entered into the Transition Agreements. Under the Services Agreement, CenterPoint Energy agreed to provideits subsidiaries hold shares of certain support services to Enable such as accounting, legal, risk management and treasury functions for an initial term, which ended on April 30, 2016.  CenterPoint Energy is providing certain services to Enable on a year-to-year basis. Enable may terminate (i) the entire Services Agreement with at least 90 days’ notice prior to the end of any extension term, or (ii) either any service provided under the Services Agreement, or the entire Services Agreement, at any time upon approval by its board of directors and with at least 180 days’ notice.

Transactions with Enable:
  Year Ended December 31,
  2017 2016 2015
  (in millions)
Reimbursement of transition services (1)
 $4
 $7
 $16
Natural gas expenses, including transportation and storage costs 115
 110
 117
Interest income related to notes receivable from Enable (2)
 —
 1
 8

(1)Represents amounts billed under the Transition Agreements, including the costs of seconded employees. Substantially all of the seconded employees became employees of Enable effective January 1, 2015. Actual transition services costs are recorded net of reimbursement.

(2)In connection with CenterPoint Energy’s purchase of Series A Preferred Units, Enable redeemed $363 million of notes owed to a wholly-owned subsidiary of CERC Corp., which bore interest at an annual rate of 2.10% to 2.45%.


  Year Ended December 31,
  2017 2016
  (in millions)
Accounts receivable for amounts billed for transition services $1
 $1
Accounts payable for natural gas purchases from Enable 13
 10

CenterPoint Energy evaluates its equity method investments for impairment when factors indicate that a decreasesecurities detailed in the value of its investment has occurred and the carrying amount of its investment may not be recoverable. An impairment loss, based on the excess of the carrying value over estimated fair value of the investment, is recognized in earnings when an impairment is deemed to be other than temporary. Considerable judgment is used in determining if an impairment loss is other than temporary and the amount of any impairment. Based on the sustained low Enable common unit price and further declines in such price during the year ended December 31, 2015, as well as the market outlook for continued depressed crude oil and natural gas prices impacting the midstream oil and gas industry, CenterPoint Energy determined that an other than temporary decrease in the value of its equity method investment in Enable had occurred. CenterPoint Energy wrote down the value of its equity method investment in Enable to its estimated fair value which resulted in impairment charges of $1,225 million for the year ended December 31, 2015. Both the income approach and market approach were utilized to estimate the fair value of CenterPoint Energy’s total investment in Enable, which includes the limited partner common and subordinated units, general partner interest and incentive distribution rights held by CenterPoint Energy. The determination of fair value considered a number of relevant factors including Enable’s common unit price and forecasted results, recent comparable transactions and the limited float of Enable’s publicly traded common units. See Note 9 for further discussion of the determination of fair value of CenterPoint Energy’s equity method investment in Enable in 2015.

As of December 31, 2017 and 2016, the carrying value of CenterPoint Energy’s equity method investment in Enable was $10.57 and $10.71 per unit, respectively, which includes limited partner common units, a general partner interest and incentive distribution rights. On December 31, 2017 and 2016, Enable’s common unit price closed at $14.22 and $15.73, respectively. There was no impairment indicated in 2017 or 2016.

As there were no identified events or changes in circumstances that may have a significant adverse effect on the fair value of CenterPoint Energy’s cost method investment in Enable’s Series A Preferred Units as of December 31, 2017 and 2016, and the investment’s fair value is not readily determinable, an estimate of the fair value of the cost method investment was not performed.

Summarized consolidated income (loss) information for Enable is as follows:
  Year Ended December 31,
  2017 2016 2015
  (in millions)
Operating revenues $2,803
 $2,272
 $2,418
Cost of sales, excluding depreciation and amortization 1,381
 1,017
 1,097
Impairment of goodwill and other long-lived assets —
 9
 1,134
Operating income (loss) 528
 385
 (712)
Net income (loss) attributable to Enable 400
 290
 (752)
       
Reconciliation of Equity in Earnings (Losses), net:      
CenterPoint Energy’s interest $216
 $160
 $(416)
Basis difference amortization (1)
 49
 48
 8
Impairment of CenterPoint Energy’s equity method investment in Enable —
 —
 (1,225)
CenterPoint Energy’s equity in earnings (losses), net (2)
 $265
 $208
 $(1,633)
(1)Equity in earnings of unconsolidated affiliates includes CenterPoint Energy’s share of Enable earnings adjusted for the amortization of the basis difference of CenterPoint Energy’s original investment in Enable and its underlying equity in net assets of Enable. The basis difference is being amortized over approximately 31 years, the average life of the assets to which the basis difference is attributed.



(2)These amounts include impairment charges totaling $1,846 million composed of CenterPoint Energy’s impairment of its equity method investment in Enable of $1,225 million and CenterPoint Energy’s share, $621 million, of impairment charges Enable recorded for goodwill and long-lived assets for the year ended December 31, 2015. This impairment is offset by $213 million of earnings for the year ended December 31, 2015.

Summarized consolidated balance sheet information for Enable is as follows:
  December 31,
  2017 2016
  (in millions)
Current assets $416
 $396
Non-current assets 11,177
 10,816
Current liabilities 1,279
 362
Non-current liabilities 2,660
 3,056
Non-controlling interest 12
 12
Preferred equity 362
 362
Enable partners’ capital 7,280
 7,420
     
Reconciliation of Investment in Enable:    
CenterPoint Energy’s ownership interest in Enable partners’ capital $3,935
 $4,067
CenterPoint Energy’s basis difference (1,463) (1,562)
CenterPoint Energy’s investment in Enable $2,472
 $2,505

(11) Indexed Debt Securities (ZENS) and Securities Related to ZENS

(a) Investment in Securities Related to ZENS

In 1995, CenterPoint Energy sold a cable television subsidiary to TW and received TW securities as partial consideration. A subsidiary of CenterPoint Energy now holds 7.1 million shares of TW Common, 0.9 million shares of Time Common and 0.9 million shares of Charter Common,table below, which are classified as trading securitiessecurities. Shares of AT&T Common, Charter Common and WBD Common are expected to be held to facilitate CenterPoint Energy’s ability to meet its obligation under the ZENS. Unrealized gains and losses resulting from changes in the market value of the TW Securities are recorded in CenterPoint Energy’s Statements of Consolidated Income.

Shares Held at December 31,Carrying Value at December 31,
2023202220232022
(in millions)
AT&T Common10,212,945 10,212,945 $171 $188 
Charter Common872,503 872,503 339 296 
WBD Common2,470,685 2,470,685 28 23 
Other3 3 
$541 $510 
141

(b) ZENS


In September 1999, CenterPoint Energy issued ZENS having an original principal amount of $1$1.0 billion, of which $828$828 million remain remained outstanding at as of December 31, 2017.2023. Each ZENS was originallyis exchangeable at the holder’s option at any time for an amount of cash equal to 95% of the market value of the reference shares of TW Common attributable to such note. The number and identity of the reference shares attributable to each ZENS are adjusted for certain corporate events. Prior to the closing of the transactions discussed below, the
CenterPoint Energy’s reference shares for each ZENS consisted of 0.5 share of TW Common, 0.125505 share of TWC Common and 0.0625 share of Time Common.the following:


On May 26, 2015, Charter announced that it had entered into a definitive merger agreement with TWC. On September 21, 2015, Charter shareholders approved the announced transaction with TWC. Pursuant to the merger agreement, upon closing of the merger, TWC Common would be exchanged for cash and Charter Common and as a result, reference shares for the ZENS would consist of Charter Common, TW Common and Time Common. The merger closed on May 18, 2016. CenterPoint Energy received $100 and 0.4891 shares of Charter Common for each share of TWC Common held, resulting in cash proceeds of $178 million and 872,531 shares of Charter Common. In accordance with the terms of the ZENS, CenterPoint Energy remitted $178 million to ZENS holders in June 2016, which reduced contingent principal.
December 31,
20232022
(in shares)
AT&T Common0.7185 0.7185 
Charter Common0.061382 0.061382 
WBD Common0.173817 0.173817 




As a result, CenterPoint Energy recorded the following during the year ended December 31, 2016:
 (in millions)
Cash payment to ZENS holders$178
Indexed debt – reduction(40)
Indexed debt securities derivative – reduction(21)
Loss on indexed debt securities$117

As of December 31, 2017, the reference shares for each ZENS consisted of 0.5 share of TW Common, 0.0625 share of Time Common and 0.061382 share of Charter Common.

On October 22, 2016, AT&T announced that it had entered into a definitive agreement to acquire TW in a stock and cash transaction. On February 15, 2017, TW shareholders approved the announced transaction with AT&T. Pursuant to the merger agreement, upon closing of the merger, TW shareholders would receive for each of their shares of TW Common an estimated implied value of $107.50, comprised of $53.75 per share in cash and $53.75 per share in AT&T Common. The stock portion will be subject to a collar such that TW shareholders will receive 1.437 shares of AT&T Common if AT&T Common’s average stock price is below $37.411 at closing and 1.3 shares of AT&T Common if AT&T Common’s average stock price is above $41.349 at closing. Cash received for the TW Common reference shares would subsequently be distributed to ZENS holders, which is expected to reduce the contingent principal balance, and reference shares would consist of Charter Common, Time Common and AT&T Common. In November 2017, the U.S. Department of Justice filed a civil antitrust lawsuit to block AT&T’s acquisition of TW. AT&T has announced it does not expect the outcome of this matter to prohibit the acquisition. Legal proceedings are expected to begin in the first or second quarter of 2018.

On November 26, 2017, Meredith announced that it had entered into a definitive merger agreement with Time. Pursuant to the merger agreement, a subsidiary of Meredith offered to purchase for cash all outstanding Time Common shares for $18.50 per share. The transaction was consummated on January 31, 2018. CenterPoint Energy elected to make a reference share offer adjustment and distribute additional interest, if any, in accordance with the terms of its ZENS rather than electing to increase the early exchange ratio to 100% during the pendency of Meredith’s tender offer for all outstanding shares of Time Common. Distributions of additional interest on the ZENS will be made by CenterPoint Energy in connection with the consummation of Meredith’s tender offer and the subsequent merger of Time with a subsidiary of Meredith. CenterPoint Energy's distribution of additional interest in connection with the reference share offer is expected to be proportionate to the percentage of eligible shares that are validly tendered by Time stockholders in Meredith’s tender offer. In accordance with the terms of the ZENS, CenterPoint Energy will remit additional interest of approximately $16 million to ZENS holders on March 6, 2018, which will reduce the contingent principal amount.

CenterPoint Energy pays interest on the ZENS at an annual rate of 2% plus the amount of any quarterly cash dividends paid in respect of the reference shares attributable to the ZENS. The principal amount of the ZENS is subject to being increasedincreases or decreaseddecreases to the extent that the annual yield from interest and cash dividends on the reference shares is less than or more than 2.309%. The adjusted principal amount is defined in the ZENS instrument as “contingent principal.” At As of December 31, 2017,2023, the ZENS, having an original principal amount of $828 million and a contingent principal amount of $505$18 million, were outstanding and were exchangeable, at the option of the holders, for cash equal to 95% of the market value of the reference shares deemed to be attributable to the ZENS. As of December 31, 2017,2023, the market value of such shares was approximately $960$538 million, which would provide an exchange amount of $1,101$618 for each $1,000 original principal amount of ZENS. At maturity of the ZENS in 2029, CenterPoint Energy will be obligated to pay in cash the higher of the contingent principal amount of the ZENS or an amount based on the then-current market value of the reference shares, which will include any additional publicly-traded securities distributed with respect to the current reference shares prior to maturity.


The ZENS obligation is bifurcated into a debt component and a derivative component (the holder’s option to receive the appreciated value of the reference shares at maturity). The bifurcated debt component accretes through interest charges at 19.5% annually up to the contingent principal amount of the ZENS in 2029. Such accretion will be reduced by annual cash interest payments, as described above. The derivative component is recorded at fair value and changes in the fair value of the derivative component are recorded in CenterPoint Energy’s Statements of Consolidated Income. Changes in the fair value of the TWZENS-Related Securities held by CenterPoint Energy are expected to substantially offset changes in the fair value of the derivative component of the ZENS.



142


The following table sets forth summarized financial information regarding CenterPoint Energy’s investment in TWZENS-Related Securities and each component of CenterPoint Energy’s ZENS obligation. 
 ZENS-Related
Securities		Debt
Component
of ZENS		Derivative
Component
of ZENS
(in millions)
Balance as of December 31, 2020$871 $15 $953 
Accretion of debt component of ZENS— 17 — 
2% interest paid— (17)— 
Distribution to ZENS holders— (5)— 
Gain on indexed debt securities— — (50)
Loss on ZENS-Related Securities(51)— — 
Balance as of December 31, 2021820 10 903 
Accretion of debt component of ZENS— 17 — 
2% interest paid— (17)— 
Distribution to ZENS holders— (3)— 
Gain on indexed debt securities— — (325)
Loss on ZENS-Related Securities(313)— — 
Balance as of December 31, 2022507 7 578 
Accretion of debt component of ZENS— 17 — 
2% interest paid— (17)— 
Distribution to ZENS holders— (2)— 
Loss on indexed debt securities— — 27 
Gain on ZENS-Related Securities31 — — 
Balance as of December 31, 2023$538 $5 $605 

 
TW
Securities
 
Debt
Component
of ZENS (1)
 
Derivative
Component
of ZENS
 (in millions)
Balance as of December 31, 2014$930
 $142
 $541
Accretion of debt component of ZENS—
 27
 —
2% interest paid—
 (17) —
Sale of TW Securities(32) —
 —
Distribution to ZENS holders—
 (7) (18)
Gain on indexed debt securities—
 —
 (81)
Loss on TW Securities(93) —
 —
Balance as of December 31, 2015805
 145
 442
Accretion of debt component of ZENS—
 26
 —
2% interest paid—
 (17) —
Sale of TW Securities(178) —
 —
Distribution to ZENS holders—
 (40) (21)
Loss on indexed debt securities—
 —
 296
Gain on TW Securities326
 —
 —
Balance as of December 31, 2016953
 114
 717
Accretion of debt component of ZENS—
 27
 —
2% interest paid—
 (17) —
Distribution to ZENS holders—
 (2) —
Gain on indexed debt securities—
 —
 (49)
Gain on TW Securities7
 —
 —
Balance as of December 31, 2017$960
 $122
 $668

(1)To reflect adoption of ASU 2015-03, balances have been restated to include unamortized debt issuance costs of $9 million and $10 million as of December 31, 2015 and 2014, respectively.

(12) Equity (CenterPoint Energy)


Dividends Declared and Paid (CenterPoint Energy)


CenterPoint Energy declared and paid dividends on its Common Stock during 2023, 2022 and 2021 as presented in the table below:

Dividends Declared Per ShareDividends Paid Per Share
202320222021202320222021
Common Stock$0.7800 $0.7200 $0.6600 $0.7700 $0.7000 $0.6500 
Series A Preferred Stock (1)
30.6250 61.2500 61.2500 61.2500 61.2500 61.2500 
Series B Preferred Stock (2)
— — 35.0000 — — 52.5000 
Series C Preferred Stock (3)
— — — — — 0.1600 

(1)All of the outstanding shares of Series A Preferred Stock were redeemed during 2023 as further described below.
(2)All of the outstanding shares of Series B Preferred Stock were converted to Common Stock during 2021.
(3)The Series C Preferred Stock was entitled to participate in any dividend or distribution (excluding those payable in Common Stock) with the Common Stock on a pari passu, pro rata, as-converted basis. The per share amount reflects the dividend per share of $1.07, $1.03Common Stock as if the Series C Preferred Stock were converted into Common Stock. All of the outstanding Series C Preferred Stock was converted to Common Stock during 2021.
143


Preferred Stock (CenterPoint Energy)

Liquidation Preference Per ShareShares Outstanding as of December 31,Outstanding Value as of December 31,
202320222021202320222021
(in millions, except shares and per share amount)
Series A Preferred Stock (1)
$1,000 — 800,000 800,000 $— $790 $790 
— 800,000 800,000 $— $790 $790 

(1)All of the outstanding shares of Series A Preferred Stock were redeemed during 2023 as further described below.

Dividend Requirement on Preferred Stock
Year Ended December 31,
202320222021
(in millions)
Series A Preferred Stock$50 $49 $49 
Series B Preferred Stock— — 46 
Total income allocated to preferred shareholders$50 $49 $95 

Series A Preferred Stock

Prior to the redemption of all outstanding shares of Series A Preferred Stock in September 2023, the aggregate liquidation value of the Series A Preferred Stock was $800 million with a per share liquidation value of $1,000. The Series A Preferred Stock was redeemable at CenterPoint Energy’s election on or after September 1, 2023, for cash at a redemption price of $1,000 per share, plus any accumulated and $0.99, respectively,unpaid dividends thereon to, but excluding, the redemption date.

Dividends. The Series A Preferred Stock accrued cumulative dividends, calculated as a percentage of the stated amount per share, at a fixed annual rate of 6.125% per annum to be paid in cash if, when and as declared. If declared, dividends were payable semi-annually in arrears on each March 1 and September 1, beginning on March 1, 2019. Cumulative dividends earned during the years ended applicable periods are presented on CenterPoint Energy’s Statements of Consolidated Income as Preferred stock dividend requirement.

Ranking. The Series A Preferred Stock, with respect to anticipated dividends and distributions upon CenterPoint Energy’s liquidation or dissolution, or winding-up of CenterPoint Energy’s affairs, ranked:

•senior to Common Stock and to each other class or series of capital stock established after the initial issue date of the Series A Preferred Stock that is expressly made subordinated to the Series A Preferred Stock;

•on a parity with any class or series of capital stock established after the initial issue date of the Series A Preferred Stock that is not expressly made senior or subordinated to the Series A Preferred Stock;

•junior to any class or series of capital stock established after the initial issue date of the Series A Preferred Stock that is expressly made senior to the Series A Preferred Stock;

•junior to all existing and future indebtedness (including indebtedness outstanding under CenterPoint Energy’s credit facilities, senior notes and commercial paper) and other liabilities with respect to assets available to satisfy claims against CenterPoint Energy; and

•structurally subordinated to any existing and future indebtedness and other liabilities of CenterPoint Energy’s subsidiaries and capital stock of CenterPoint Energy’s subsidiaries held by third parties.

Voting Rights. Holders of the Series A Preferred Stock generally did not have voting rights.

144

Redemption of Series A Preferred Stock. On September 1, 2023, CenterPoint Energy redeemed all 800,000 outstanding shares of Series A Preferred Stock, in whole for cash at a redemption price of $1,000 per share, plus any accumulated and unpaid dividends thereon to, but excluding, the redemption date.

Temporary Equity (CenterPoint Energy)

On the approval and recommendation of the Compensation Committee and approval of the Board (acting solely through its independent directors), CenterPoint Energy entered into a retention incentive agreement with David J. Lesar, then President and Chief Executive Officer of CenterPoint Energy, dated July 20, 2021. Pursuant to the retention incentive agreement, Mr. Lesar received equity-based awards under CenterPoint Energy’s LTIP covering a total of 1 million shares of Common Stock (Total Stock Award), which were granted in multiple annual awards. Mr. Lesar received 400 thousand restricted stock units in July 2021 that vested in December 2022 and 400 thousand restricted stock units and 200 thousand restricted stock units in February 2022 and February 2023, respectively, that vested in December 2023. For accounting purposes, the 1 million shares under the Total Stock Award, consisting of the equity-based awards described above, were considered granted in July 2021. In the event that death, disability, termination without cause or resignation for good reason, as defined in the retention incentive agreement, had occurred prior to the full Total Stock Award being awarded, CenterPoint Energy would have paid a lump sum cash payment equal to the value of the unawarded equity-based awards, based on the closing trading price of Common Stock on the date of the event’s occurrence. Because the equity-based awards would have been redeemable for cash prior to being awarded upon events that were not probable at the grant date, the equity associated with any unawarded equity-based awards were classified as Temporary Equity as of December 31, 20172022 on CenterPoint Energy’s Consolidated Balance Sheets. As of December 31, 2023, all restricted stock units have been awarded to Mr. Lesar and no amounts are reflected in Temporary Equity on CenterPoint Energy’s Consolidated Balance Sheets.

Accumulated Other Comprehensive Income (Loss) (CenterPoint Energy and CERC)

Changes in accumulated comprehensive income (loss) are as follows:
Year Ended December 31,
20232022
CenterPoint EnergyCERCCenterPoint EnergyCERC
(in millions)
Beginning Balance$(31)$16 $(64)$10 
Other comprehensive income (loss) before reclassifications:
Remeasurement of pension and other postretirement plans(8)— (40)10 
Amounts reclassified from accumulated other comprehensive loss:
Net deferred gain from cash flow hedges1 — — — 
Prior service cost (1)
1 (2)(1)(1)
Actuarial losses (1)
1 2 8 1 
Settlement (2)
— — 67 — 
Reclassification of deferred loss from cash flow hedges realized in net income— — 1 — 
Tax benefit (expense)1 — (2)(4)
Net current period other comprehensive income (loss)(4)— 33 6 
Ending Balance$(35)$16 $(31)$16 

(1)Amounts are included in the computation of net periodic cost and are reflected in Other, net in each of the Registrants’ respective Statements of Consolidated Income.
(2)Amounts presented represent a one-time, non-cash settlement cost (benefit), 2016prior to regulatory deferrals, which are required when the total lump sum distributions or other settlements of plan benefit obligations during a plan year exceed the service cost and 2015.interest cost components of the net periodic cost for that year. Amounts presented in the table above are included in Other income (expense), net in CenterPoint Energy’s Statements of Consolidated Income, net of regulatory deferrals.


On
145

(13) Short-term Borrowings and Long-term Debt

Short-term Borrowings and Long-term Debt: As of December 13, 2017, our Board31, 2023 and 2022, the Registrants had the following short-term borrowings and long-term debt outstanding:
 December 31, 2023December 31, 2022
 Long-Term
Current (1)
Long-Term
Current (1)
 (in millions)
CenterPoint Energy:
ZENS due 2029 (2)
$— $5 $— $7 
CenterPoint Energy senior notes 1.45% to 5.989% due 2024 to 20493,250 850 3,050 — 
CenterPoint Energy pollution control bonds 5.125% due 2028 (3)
68 — 68 — 
CenterPoint Energy commercial paper (4)
1,036 — 1,770 — 
SIGECO first mortgage bonds 3.450% to 6.00% due 2024 to 2055 (5)
825 22 277 11 
SIGECO securitization bonds 5.026% to 5.172% due 2036 to 2041 (6)
324 17 — — 
Other debt— — — 4 
Unamortized debt issuance costs(35)— (15)— 
Unamortized discount and premium, net(5)—(6)— 
Houston Electric debt (see details below)7,426 161 6,197 156 
CERC debt (see details below)4,670 4 3,495 1,842 
Total CenterPoint Energy debt$17,559 $1,059 $14,836 $2,020 
Houston Electric:    
General mortgage bonds 2.35% to 6.95% due 2026 to 2053 (7)
$7,512 $— $6,112 $— 
Other1 — 1 — 
Bond Company IV:
Transition bonds 3.028% due 2024— 161 161 156 
Unamortized debt issuance costs(59)— (50)— 
Unamortized discount and premium, net(28)— (27)— 
Total Houston Electric debt$7,426 $161 $6,197 $156 
CERC (8):
Short-term borrowings:    
Inventory financing (9)
$— $4 $— $11 
Term loan— — — 500 
Total CERC short-term borrowings— 4 — 511 
Long-term debt:    
Senior notes 1.75% to 6.625% due 2026 to 2047$4,120 $— $2,620 $1,331 
Indiana Gas senior notes 6.34% to 7.08% due 2025 to 202996 — 96 — 
Commercial paper (4)
484 — 805 — 
Unamortized debt issuance costs(31)— (22)— 
Unamortized discount and premium, net1 — (4)— 
Total CERC debt$4,670 $4 $3,495 $1,842 

(1)Includes amounts due or exchangeable within one year of Directors declaredthe date noted.
(2)CenterPoint Energy’s ZENS obligation is bifurcated into a regular quarterlydebt component and an embedded derivative component. For additional information regarding ZENS, see Note 11(b). As ZENS are exchangeable for cash dividendat any time at the option of $0.2775the holders, these notes are classified as a current portion of long-term debt.
146

(3)These pollution control bonds were secured by general mortgage bonds of Houston Electric as of December 31, 2023 and 2022 and are not reflected in Houston Electric’s consolidated financial statements because of the contingent nature of the obligations.
(4)Commercial paper issued by CenterPoint Energy and CERC Corp. has maturities up to 60 days and 30 days, respectively, and are backstopped by the respective issuer’s long-term revolving credit facility. Commercial paper is classified as long-term because the termination date of the facility that backstops the commercial paper is more than one year from the balance sheet date.
(5)The first mortgage bonds issued by SIGECO subject SIGECO’s properties to a lien under the related mortgage indenture as further discussed below.
(6)Scheduled final payment dates are November 15, 2036 and May 15, 2041. The SIGECO Securitization Bonds will be repaid over time through a securitization charge imposed on retail electric customers in SIGECO’s service territory.
(7)The general mortgage bonds issued by Houston Electric subject Houston Electric’s properties to a lien under the General Mortgage as further discussed below.
(8)Issued by CERC Corp.
(9)Represents AMA transactions accounted for as an inventory financing.

Debt Transactions

Debt Issuances. During 2023, the following debt instruments were issued or incurred:
RegistrantIssuance DateDebt InstrumentAggregate Principal AmountInterest RateMaturity Date
(in millions, except for interest rates)
Houston Electric (1)
March 2023General Mortgage Bonds$600 4.95%2033
Houston Electric (1)
March 2023General Mortgage Bonds300 5.30%2053
Houston Electric (2)
September 2023General Mortgage Bonds500 5.20%2028
Total Houston Electric1,400 
CERC (3)
February 2023Term Loan500 
SOFR (4) + 0.85%
2024
CERC (5)
February 2023Senior Notes600 5.25%2028
CERC (5)
February 2023Senior Notes600 5.40%2033
CERC (6)
May 2023Senior Notes300 5.25%2028
Total CERC2,000 
CenterPoint Energy (7)
March 2023First Mortgage Bonds100 4.98%2028
CenterPoint Energy (7)
March 2023First Mortgage Bonds80 5.04%2033
CenterPoint Energy (8)
March 2023Term Loan250 
SOFR (4) + 1.50%
2023
CenterPoint Energy (9)
June 2023Securitization Bonds341 5.026% - 5.172%2038-2043
CenterPoint Energy (10)
August 2023Convertible Notes1,000 4.25%2026
CenterPoint Energy (11)
August 2023Senior Notes400 5.25%2026
CenterPoint Energy (12)
October 2023First Mortgage Bonds470 5.75% - 6.00%2029-2034
Total CenterPoint Energy$6,041 

(1)Total proceeds from Houston Electric’s March 2023 issuances of general mortgage bonds, net of transaction expenses and fees, were approximately $890 million. Approximately $593 million of such proceeds were used for general limited liability company purposes, including capital expenditures, working capital and the repayment of all or a portion of Houston Electric’s borrowings under the CenterPoint Energy money pool, and approximately $296 million of such proceeds will be disbursed or allocated to finance or refinance, in part or in full, new or existing projects that meet stated criteria.
(2)Total proceeds from Houston Electric’s September 2023 issuances of general mortgage bonds, net of transaction expenses and fees, of approximately $496 million were used for general limited liability company purposes, including capital expenditures, working capital and the repayment of all of Houston Electric’s borrowings under the CenterPoint Energy money pool.
(3)Total proceeds, net of transaction expenses and fees, of approximately $500 million were used for general corporate purposes, including the repayment of CERC’s outstanding commercial paper balances.
(4)As defined in the term loan agreement, which includes an adjustment of 0.10% per share,annum.
147

(5)Total proceeds from CERC’s February 2023 issuances of senior notes, net of transaction expenses and fees, of approximately $1.2 billion were used for general corporate purposes, including the repayment of (i) all or a portion of CERC’s outstanding 0.700% senior notes due 2023, (ii) all or a portion of CERC’s outstanding floating rate senior notes due 2023 and (iii) a portion of CERC’s outstanding commercial paper balances.
(6)Total proceeds, including issuance premiums and approximately $3 million of accrued interest, and net of transaction expenses and fees, of approximately $308 million were used for general corporate purposes, including repayment of a portion of CERC’s outstanding $500 million term loan due February 2024.
(7)Issued by SIGECO. Total proceeds from SIGECO’s March 2023 issuances of first mortgage bonds, net of transaction expenses and fees, of approximately $179 million were used for general corporate purposes, including repaying short-term debt.
(8)Total proceeds, net of transaction expenses and fees, of approximately $250 million were used for general corporate purposes, including the repayment of CenterPoint Energy’s outstanding commercial paper balances. The full outstanding amount of the term loan, including accrued and unpaid interest, was repaid in March 2023 and, following the repayment, the term loan agreement was terminated.
(9)Issued by SIGECO Securitization Subsidiary. Total proceeds from SIGECO Securitization Subsidiary’s June 2023 issuance of SIGECO Securitization Bonds, net of transaction expenses and fees, of approximately $337 million were used to pay SIGECO the purchase price of the securitization property. SIGECO used the net proceeds from the sale of the securitization property (after payment of upfront financing costs) to reimburse or pay for qualified costs approved by the IURC related to the completed retirement of its A.B. Brown 1 and 2 coal-powered generation units. See Notes 2 and 7 for further details.
(10)Total proceeds, net of discounts, transaction fees and expenses, of $985 million were used for general corporate purposes, including the redemption of CenterPoint Energy’s Series A Preferred Stock after its September 1, 2023 redemption date, and the repayment of a portion of CenterPoint Energy’s outstanding commercial paper. See additional information below.
(11)Total proceeds, net of discounts, transaction fees and expenses, of $397 million were used for general corporate purposes and the repayment of a portion of CenterPoint Energy’s outstanding commercial paper.
(12)SIGECO issued in three tranches: (i) $180 million first mortgage bonds bearing interest at 5.75% due 2029; (ii) $105 million first mortgage bonds bearing interest at 5.91% due 2030; and (iii) $185 million first mortgage bonds bearing interest at 6.00% due 2034. The net proceeds of $467 million were used for general corporate purposes.

In April 2023, SIGECO executed a remarketing agreement to remarket five series of tax-exempt debt issued by the Indiana Finance Authority, and secured by SIGECO first mortgage bonds, of approximately $148 million, comprised of: (i) $107 million aggregate principal amount of Environmental Improvement Refunding Revenue Bonds, Series 2013, originally issued by the Indiana Finance Authority on April 26, 2013, and (ii) $41 million aggregate principal amount of Environmental Improvement Refunding Revenue Bonds, Series 2014, originally issued by the Indiana Finance Authority on September 24, 2014, which closed on May 1, 2023.

In July 2023, SIGECO executed a remarketing agreement to remarket two series of tax-exempt debt issued by the City of Mount Vernon, Indiana and Warrick County, Indiana, and secured by SIGECO first mortgage bonds, of approximately $38 million, comprised of: (i) $23 million aggregate principal amount of Environmental Improvement Revenue Bonds, Series 2015 issued by the City of Mount Vernon and (ii) $15 million aggregate principal amount of Environmental Improvement Revenue Bonds, Series 2015 issued by Warrick County, which closed on September 1, 2023. Effective September 1, 2023, the bonds of each series bear interest at a fixed rate of 4.250% per annum to the earlier of (i) its redemption date or (ii) September 1, 2028, at which time the bonds are subject to mandatory tender.

Convertible Senior Notes. Interest on the Convertible Notes described in the table above is payable semiannually in arrears on March 8, 2018February 15 and August 15 of each year, beginning on February 15, 2024. The Convertible Notes will mature on August 15, 2026, unless earlier converted or repurchased by CenterPoint Energy in accordance with their terms.

Prior to shareholders of record at the close of business on Februarythe business day immediately preceding May 15, 2018.2026, the Convertible Notes are convertible only under certain conditions. On or after May 15, 2026 until the close of business on the second scheduled trading day immediately preceding the maturity date, holders may convert all or any portion of their Convertible Notes at any time at the conversion rate then in effect, irrespective of the conditions. CenterPoint Energy may not redeem the Convertible Notes prior to the maturity date and no sinking fund is provided for the Convertible Notes.


Undistributed Retained Earnings

AsUpon conversion of both December 31, 2017the Convertible Notes, CenterPoint Energy will pay cash up to the aggregate principal amount of the Convertible Notes to be converted and 2016,pay or deliver, as the case may be, cash, shares of Common Stock, or a combination of cash and shares of Common Stock, at CenterPoint Energy’s consolidated retained earnings balance includes undistributed earnings from Enableelection, in respect of $-0-.



(13) Short-term Borrowings and Long-term Debtthe remainder, if any, of CenterPoint
148

 December 31,
2017		 December 31,
2016
 Long-Term 
Current (1)
 Long-Term 
Current (1)
 (in millions)
Short-term borrowings:       
Inventory financing (2)
$—
 $39
 $—
 $35
Total short-term borrowings—
 39
 —
 35
Long-term debt: 
  
  
  
CenterPoint Energy: 
  
  
  
ZENS due 2029 (3)
—
 122
 —
 114
Senior notes 2.50% due 2022500
 —
 —
 250
Pollution control bonds 5.05% to 5.125% due 2018 to 2028 (4)
68
 50
 118
 —
Commercial paper (5)
855
 —
 835
 —
Houston Electric: 
  
  
  
First mortgage bonds 9.15% due 2021102
 —
 102
 —
General mortgage bonds 1.85% to 6.95% due 2021 to 20442,812
 —
 2,512
 —
System restoration bonds 3.46% to 4.243% due 2018 to 2022256
 56
 312
 53
Transition bonds 2.161% to 5.302% due 2019 to 20241,181
 378
 1,560
 358
CERC Corp.: 
  
  
  
Senior notes 4.10% to 6.625% due 2021 to 20471,593
 —
 1,593
 250
Commercial paper (5)
898
 —
 569
 —
Unamortized debt issuance costs(38) —
 (33) —
Unamortized discount and premium, net(32) —
 (36) —
Total long-term debt8,195
 606
 7,532
 1,025
Total debt$8,195
 $645
 $7,532
 $1,060
Energy’s conversion obligation in excess of the aggregate principal amount of the Convertible Notes being converted. The conversion rate for the Convertible Notes is initially 27.1278 shares of Common Stock per $1,000 principal amount of Convertible Notes (equivalent to an initial conversion price of approximately $36.86 per share of Common Stock). The initial conversion price of the Convertible Notes represents a premium of approximately 25.0% over the last reported sale price of the Common Stock on the New York Stock Exchange on August 1, 2023. Initially, a maximum of 33,909,700 shares of Common Stock may be issued upon conversion of the Convertible Notes based on the initial maximum conversion rate of 33.9097 shares of Common Stock per $1,000 principal amount of Convertible Notes. The conversion rate will be subject to adjustment in some events (as described in the Convertible Notes Indenture) but will not be adjusted for any accrued and unpaid interest.

(1)Includes amounts due or exchangeable within one year of the date noted.

(2)NGD has AMAs associated with its utility distribution service in Arkansas, Louisiana, Mississippi, Oklahoma and Texas. The AMAs have varying terms, the longest of which expires in 2020. Pursuant to the provisions of the agreements, NGD sells natural gas and agrees to repurchase an equivalent amount of natural gas during the winter heating seasons at the same cost, plus a financing charge. These transactions are accounted for as an inventory financing.

(3)CenterPoint Energy’s ZENS obligation is bifurcated into a debt component and an embedded derivative component. For additional information regarding ZENS, see Note 11(b). As ZENS are exchangeable for cash at any time at the option of the holders, these notes are classified as a current portion of long-term debt.

(4)
$118 million of these series of debt were secured by general mortgage bonds of Houston Electric as of both December 31, 2017 and 2016.

(5)Classified as long-term debt because the termination date of the facility that backstops the commercial paper is more than one year from the date noted.


Long-term Debt

Debt Retirements. In February 2017,addition, following certain corporate events that occur prior to the maturity date of the Convertible Notes, CenterPoint Energy retired $250will, in certain circumstances, increase the conversion rate for a holder who elects to convert its Convertible Notes in connection with such a corporate event. If CenterPoint Energy undergoes a fundamental change (as defined in the Convertible Notes Indenture), holders of the Convertible Notes may require CenterPoint Energy to repurchase for cash all or any portion of their Convertible Notes at a fundamental change repurchase price equal to 100% of the principal amount of the Convertible Notes to be repurchased, plus accrued and unpaid interest to, but excluding, the fundamental change repurchase date.

The Convertible Notes are senior unsecured obligations of CenterPoint Energy and rank senior in right of payment to any of CenterPoint Energy’s indebtedness that is expressly subordinated in right of payment to the Convertible Notes; equal in right of payment to any of CenterPoint Energy’s unsecured indebtedness that is not so subordinated; effectively junior in right of payment to any of CenterPoint Energy’s secured indebtedness it may incur in the future to the extent of the value of the assets securing such future secured indebtedness; and structurally junior to all indebtedness and other liabilities (including trade payables but excluding intercompany obligations and liabilities of a type not required to be reflected on a balance sheet of such subsidiaries in accordance with generally accepted accounting principles) of CenterPoint Energy’s subsidiaries.

Debt Repayments and Redemptions. During 2023, the following debt instruments were repaid at maturity or redeemed prior to maturity:

RegistrantRepayment/Redemption DateDebt InstrumentAggregate PrincipalInterest RateMaturity Date
(in millions)
CERC
March 2023
Term Loan (1)
$500 
SOFR (2) + 0.70%
2023
CERC
March 2023Senior Notes700 0.70%2023
CERC
March 2023Floating Rate Senior Notes575 Three-month LIBOR plus 0.5%2023
CERCMay 2023
Term Loan (3)
500 
SOFR (2) + 0.85%
2024
CERCDecember 2023Senior Notes57 3.72%2023
Total CERC2,332 
CenterPoint Energy (4)
January 2023First Mortgage Bonds11 4.00%2044
CenterPoint EnergyMarch 2023
Term Loan (1)
250 
SOFR (2) + 1.50%
2023
CenterPoint Energy (5)
December 2023Floating Rate Senior Notes350 SOFR plus 0.65%2024
CenterPoint Energy (6)
December 2023First Mortgage Bonds80 6.72%2029
Total CenterPoint Energy$3,023 

(1) The full outstanding amount of the term loan, including accrued and unpaid interest, was repaid in March 2023 and, following the repayment, the term loan agreement was terminated.
(2)    As defined in the term loan agreement, which includes an adjustment of 0.10% per annum.
(3) The full outstanding amount of the term loan, including accrued and unpaid interest, was repaid in May 2023 and, following the repayment, the term loan agreement was terminated.
(4)    On December 16, 2022, SIGECO provided notice of redemption and on January 17, 2023, SIGECO redeemed $11 million aggregate principal amount of its 5.95% senior notes at their maturity. The retirement of senior notes was financed by the issuance of commercial paper.



In November 2017, CERC Corp. retired $250 million aggregate principal amount of its 6.125% senior notes at their maturity. The retirement of senior notes was financed by the issuance of commercial paper.

In December 2017, CERC Corp. redeemed $300 million aggregate principal amount of its 6.00% senior notesSIGECO’s outstanding first mortgage bonds due 20182044 at a redemption price equal to 100% of the principal amount thereof,of the first mortgage bonds to be redeemed plus accrued and unpaid interest thereon, if any, to, but excluding, the redemption date.
(5) On November 30, 2023, CenterPoint Energy provided notice of redemption and on December 15, 2023, CenterPoint Energy redeemed $350 million aggregate principal amount of outstanding floating rate senior notes due 2024 at a redemption price equal to 100% of the principal amount of the floating rate senior notes to be redeemed plus accrued and unpaid interest thereon, if any, to, but excluding, the redemption date.
149

(6) On November 17, 2023, SIGECO provided notice of redemption and on December 19, 2023, SIGECO redeemed $80 million aggregate principal amount of outstanding first mortgage bonds due 2029 at a redemption price equal to the sum of remaining principal and interest payments discounted at the treasury yield plus 10 basis points, plus interest accrued to the redemption date plus theand an applicable make-whole premium.

The Registrants recorded the following losses on early extinguishment of debt, including make-whole premium associated with the redemption was approximately $5 millionpremiums and was includedrecognition of deferred debt related costs, in Other Income, netInterest expense and other finance charges on thetheir respective Statements of Consolidated Income.Income unless specified otherwise:


Debt Issuances. During the year ended
Year Ended December 31,
202320222021
(in millions)
CenterPoint Energy (1)
$11 $47 $53 
CERC
— — 11
Houston Electric (2)
— 2— 

(1) The loss on early extinguishment of debt at CenterPoint Energy during 2023 was recorded as a regulatory asset.
(2) The loss on early extinguishment of debt at Houston Electric during 2022 was recorded as a regulatory asset.

Securitization Bonds. As of December 31, 2017,2023, CenterPoint Energy, Houston Electric and CERC Corp. issued the following debt instruments:

  Issuance Date Debt Instrument Aggregate Principal Amount Interest Rate Maturity Date
      (in millions)    
Houston Electric January 2017 General mortgage bonds $300
 3.00% 2027
CenterPoint Energy August 2017 Unsecured senior notes   500
 2.50% 2022
CERC Corp. August 2017 Unsecured senior notes   300
 4.10% 2047

The proceeds from these issuances were used for general limited liability company and corporate purposes, as applicable, including to repay portions of outstanding commercial paper.

Securitization Bonds. As of December 31, 2017, Houston ElectricSIGECO had special purpose subsidiaries consisting ofincluding the Bond Companies and the SIGECO Securitization Subsidiary, which it consolidates.are consolidated. The consolidated special purpose subsidiaries are wholly-owned, bankruptcy remote entities that were formed solely for the purpose of purchasing and owningsecuritizing transition property or system restoration propertyfacilitating the securitization financing of qualified costs in the second quarter of 2023 associated with the completed retirement of SIGECO’s A.B. Brown coal generation facilities through the issuance of transition bonds or system restorationsecuritization bonds and activities incidental thereto. TheseThe Securitization Bonds issued by Bond Company IV are payable only through the imposition and collection of “transition” or “system restoration”transition charges, as defined in the Texas Public Utility Regulatory Act, which are irrevocable, non-bypassable charges to provide recovery of authorized qualified costs. The SIGECO Securitization Bonds are payable only through the imposition of securitization charges payable by SIGECO’s retail electric customers, which are non-bypassable charges to provide recovery of the qualified costs of SIGECO authorized by the IURC order. CenterPoint Energy, Houston Electric hasand SIGECO have no payment obligations in respect of the Securitization Bonds issued by Bond Company IV or the SIGECO Securitization Bonds other than to remit the applicable transition or system restorationsecuritization charges it collects.they collect as set forth in servicing agreements among Houston Electric, the Bond Companies, SIGECO, the SIGECO Securitization Subsidiary and other parties. Each special purpose entity is the sole owner of the right to impose, collect and receive the applicable transition or system restorationand securitization charges securing the bonds issued by that entity. Creditors of CenterPoint Energy, or Houston Electric and SIGECO have no recourse to any assets or revenues of the Bond Companies (including the transition and system restoration charges), or the SIGECO Securitization Subsidiary, as applicable, and the holders of Securitization Bondsbondholders have no recourse to the assets or revenuesto the general credit of CenterPoint Energy or Houston Electric.

Credit Facilities. In June 2017, CenterPoint Energy, Houston Electric and CERC Corp. each entered into amendments to their respectiveor SIGECO.

Credit Facilities. The Registrants had the following revolving credit facilities to extendas of December 31, 2023:
Execution
 Date		RegistrantSize of
Facility
Draw Rate of SOFR plus (1)
Financial Covenant Limit on Debt for Borrowed Money to Capital Ratio 
Debt for Borrowed Money to Capital
Ratio as of December 31, 2023 (2)
Termination
 Date
(in millions)
December 6, 2022CenterPoint Energy$2,400 1.500%65%(3)59.6%December 6, 2027
December 6, 2022
CenterPoint Energy (4)
250 1.125%65%46.5%December 6, 2027
December 6, 2022Houston Electric300 1.250%67.5%(3)52.6%December 6, 2027
December 6, 2022
CERC
1,050 1.125%65%40.2%December 6, 2027
Total$4,000 

(1)Based on credit ratings as of December 31, 2023.
(2)As defined in the termination date thereof from March 3, 2021 to March 3, 2022 and to terminate the swingline loan subfacility thereunder. The amendments to therevolving credit facility agreement, excluding Securitization Bonds.
(3)For CenterPoint Energy and CERC Corp. revolving credit facilities also increasedHouston Electric, the aggregate commitments byfinancial covenant limit will temporarily increase to 70% if Houston Electric experiences damage from a natural disaster in its service territory and CenterPoint Energy certifies to the
150

administrative agent that Houston Electric has incurred system restoration costs reasonably likely to exceed $100 million and $300 million, respectively, to $1.7 billion and $900 million under their respective revolving credit facilities. No changes were made to the aggregate commitments under thein a consecutive 12-month period, all or part of which Houston Electric revolving credit facility. In connection withintends to seek to recover through securitization financing. Such temporary increase in the amendments to increasefinancial covenant would be in effect from the aggregate commitments under their respective revolving credit facilities,date CenterPoint Energy and CERC Corp. each increaseddelivers its certification until the sizeearliest to occur of their respective commercial paper programs to permit(i) the issuancecompletion of commercial paper notesthe securitization financing, (ii) the first anniversary of CenterPoint Energy’s certification or (iii) the revocation of such certification.
(4)This credit facility was issued by SIGECO.

The Registrants, as well as the subsidiaries of CenterPoint Energy discussed above, were in an aggregate principal amount not to exceed $1.7 billion and $900 million, respectively, at any time outstanding.compliance with all financial debt covenants as of December 31, 2023.


As of December 31, 20172023 and 2016, CenterPoint Energy, Houston Electric and CERC Corp.2022, the Registrants had the following revolving credit facilities and utilization of such facilities:
December 31, 2023December 31, 2022
RegistrantSize of
Facility		LoansLetters
of Credit		Commercial
Paper		Weighted Average Interest RateSize of
Facility		LoansLetters
of Credit		Commercial
Paper		Weighted Average Interest Rate
(in millions, except weighted average interest rate)
CenterPoint Energy (1)
$2,400 $— $— $1,036 5.54 %$2,400 $— $11 $1,770 4.71 %
CenterPoint Energy (2)
250 — — — — %250 — — — — %
Houston Electric300 — — — — %300 — — — — %
CERC1,050 — 1 484 5.53 %1,050 — — 805 4.67 %
Total$4,000 $— $1 $1,520 $4,000 $— $11 $2,575 
 December 31, 2017 December 31, 2016 
 Size of
Facility		 Loans Letters
of Credit		 Commercial
Paper		 Size of
Facility		 Loans Letters
of Credit		 Commercial
Paper		 
 (in millions) 
CenterPoint Energy$1,700
 $—
 $6
 $855
(1)$1,600
 $—
 $6
 $835
(1)
Houston Electric300
 —
 4
 —
 300
 —
 4
 —
 
CERC Corp.900
 —
 1
 898
(2)600
 —
 4
 569
(2)
Total$2,900
 $—
 $11
 $1,753
 $2,500
 $—
 $14
 $1,404
 


(1)Weighted average interest rate was 1.88% and 1.04% as of December 31, 2017 and December 31, 2016, respectively.

(1)CenterPoint Energy’s and CERC’s outstanding commercial paper generally have maturities up to 60 days and 30 days, respectively, and are backstopped by the respective issuer’s long-term revolving credit facility.

(2)This credit facility was issued by SIGECO.

(2)Weighted average interest rate was 1.72% and 1.03% as of December 31, 2017 and December 31, 2016, respectively.


Execution
 Date
 Company 
Size of
Facility
 
Draw Rate of LIBOR plus (2)
 Financial Covenant Limit on Debt for Borrowed Money to Capital Ratio 
Debt for Borrowed Money to Capital
Ratio as of
December 31, 2017 (3)
 
Termination Date (5)
    (in millions)        
March 3, 2016 CenterPoint Energy $1,700
(1)1.250% 65%(4)52.9% March 3, 2022
March 3, 2016 Houston Electric 300
 1.125% 65%(4)48.6% March 3, 2022
March 3, 2016 CERC Corp. 900
(1)1.250% 65% 40.4% March 3, 2022

(1)Amended on June 16, 2017 to increase the aggregate commitment size as noted above.

(2)Based on current credit ratings.

(3)Maturities.As defined in the revolving credit facility agreement, excluding Securitization Bonds.

(4)The financial covenant limit will temporarily increase from 65% to 70% if Houston Electric experiences damage from a natural disaster in its service territory and CenterPoint Energy certifies to the administrative agent that Houston Electric has incurred system restoration costs reasonably likely to exceed $100 million in a consecutive 12-month period, all or part of which Houston Electric intends to seek to recover through securitization financing. Such temporary increase in the financial covenant would be in effect from the date CenterPoint Energy delivers its certification until the earliest to occur of (i) the completion of the securitization financing, (ii) the first anniversary of CenterPoint Energy’s certification or (iii) the revocation of such certification.

(5)Amended on June 16, 2017 to extend the termination date as noted above.

CenterPoint Energy, Houston Electric and CERC Corp. were in compliance with all financial debt covenants as of December 31, 2017.

Maturities.  Maturities2023, maturities of long-term debt capital leases and sinking fund requirements,through 2028, excluding the ZENS obligation areand unamortized discounts, premiums and issuance costs, were as follows:
CenterPoint
Energy (1)
Houston
 Electric (1)
CERCSecuritization Bonds
(in millions)
2024$1,050 $161 $— $178 
202564 — 10 13 
20262,274 300 60 14 
20271,860 300 510 14 
20282,063 500 1,230 15 
 
CenterPoint
Energy (1)
 Securitization Bonds
 (in millions)
2018$484
 $434
2019458
 458
2020231
 231
20211,206
 211
20222,773
 219


(1)These maturities include Securitization Bonds principal repayments on scheduled payment dates.

(1)These maturities include Securitization Bonds principal repayments on scheduled payment dates.

Liens.As of December 31, 2017,2023, Houston Electric’s assets were subject to liens securing approximately $102 million of first mortgage bonds. Sinking or improvement fund and replacement fund requirements on the first mortgage bonds may be satisfied by certification of property additions. Sinking fund and replacement fund requirements for 2017, 2016 and 2015 have been satisfied by certification of property additions. The replacement fund requirement to be satisfied in 2018 is approximately $266 million, and the sinking fund requirement to be satisfied in 2018 is approximately $1.6 million. CenterPoint Energy expects Houston Electric to meet these 2018 obligations by certification of property additions. As of December 31, 2017, Houston Electric’s assets were also subject to liens securing approximately $2.9$7.6 billion of general mortgage bonds outstanding under the General Mortgage, including approximately $68 million held in trust to secure pollution control bonds that mature in 2028 for which CenterPoint Energy is obligated. The general mortgage bonds that are juniorheld in trust to secure pollution control bonds are not reflected in Houston Electric’s consolidated financial statements because of the contingent nature of the obligations. Houston Electric may issue additional general mortgage bonds on the basis of retired bonds, 70% of property additions or cash deposited with the trustee. As of December 31, 2023, approximately $4.8 billion of additional general mortgage bonds could be issued on the basis of retired bonds and 70% of property additions. No first mortgage bonds are outstanding under the M&DOT, and Houston Electric is contractually obligated to not issue any additional first mortgage bonds under the M&DOT and is undertaking actions to release the lien of the M&DOT and terminate the M&DOT.

As of December 31, 2023, SIGECO had approximately $847 million aggregate principal amount of first mortgage bonds outstanding. Generally, all of SIGECO’s real and tangible property is subject to the lienslien of theSIGECO’s mortgage indenture which was amended and restated effective as of January 1, 2023. As of December 31, 2023, SIGECO was permitted to issue additional bonds under its mortgage indenture up to 70% of then currently unfunded property additions and approximately $966 million of additional first mortgage bonds.bonds could be issued on this basis.




151


Houston Electric and CERC participate in a money pool through which they can borrow or invest on a short-term basis. For additional information, see Note 19.

(14) Income Taxes


The components of CenterPoint Energy’sthe Registrant’s income tax expense (benefit) were as follows:
Year Ended December 31,
202320222021
(in millions)
CenterPoint Energy - Continuing Operations
Current income tax expense (benefit):
Federal$106 $294 $— 
State33 46 (28)
Total current expense (benefit)139 340 (28)
Deferred income tax expense (benefit):
Federal119 16 78 
State(88)4 60 
Total deferred expense31 20 138 
Total income tax expense$170 $360 $110 
CenterPoint Energy - Discontinued Operations
Current income tax expense:
Federal$— $— $91 
State— — 35 
Total current expense— — 126 
Deferred income tax expense (benefit):
Federal— — 127 
State— — (52)
Total deferred expense (benefit)— — 75 
Total income tax expense (benefit)$— $— $201 
Houston Electric
Current income tax expense (benefit):
Federal$(26)$23 $22 
State34 16 22 
Total current expense8 39 44 
Deferred income tax expense (benefit):
Federal159 86 31 
State1 — 1 
Total deferred expense (benefit)160 86 32 
Total income tax expense$168 $125 $76 
CERC - Continuing Operations
Current income tax expense (benefit):
Federal$12 $30 $— 
State3 28 (25)
Total current expense (benefit)15 58 (25)
Deferred income tax expense (benefit):
Federal95 164 67 
State(136)14 34 
Total deferred expense (benefit)(41)178 101 
Total income tax expense (benefit)$(26)$236 $76 
152
 Year Ended December 31,
 2017 2016 2015
 (in millions)
Current income tax expense (benefit):     
Federal$32
 $23
 $(37)
State9
 18
 12
Total current expense (benefit)41
 41
 (25)
Deferred income tax expense (benefit): 
  
  
Federal(806) 185
 (359)
State36
 28
 (54)
Total deferred expense (benefit)(770) 213
 (413)
Total income tax expense (benefit)$(729) $254
 $(438)


A reconciliation of income tax expense (benefit) using the federal statutory income tax rate to the actual income tax expense and resulting effective income tax rate is as follows:
Year Ended December 31,
202320222021
(in millions)
CenterPoint Energy - Continuing Operations (1) (2) (3)
Income before income taxes$1,087 $1,417 $778 
Federal statutory income tax rate21 %21 %21 %
Expected federal income tax expense228 298 163 
Increase (decrease) in tax expense resulting from:
State income tax expense, net of federal income tax25 46 63 
State valuation allowance, net of federal income tax— — (15)
State law change, net of federal income tax(69)— (23)
Equity AFUDC(13)(8)(6)
Excess deferred income tax amortization(44)(51)(75)
Goodwill impairment— 84 — 
Sale of Energy Systems Group28 — — 
Other, net15 (9)3 
Total(58)62 (53)
Total income tax expense$170 $360 $110 
Effective tax rate16 %25 %14 %
CenterPoint Energy - Discontinued Operations (4)
Income before income taxes$— $— $1,019 
Federal statutory income tax rate— %— %21 %
Expected federal income tax expense— — 214 
Increase (decrease) in tax expense resulting from:
State income tax expense, net of federal income tax— — 14 
State law change, net of federal income tax— — (27)
Total— — (13)
Total income tax expense$— $— $201 
Effective tax rate— %— %20 %
Houston Electric (5) (6) (7)
Income before income taxes$761 $635 $457 
Federal statutory income tax rate21 %21 %21 %
Expected federal income tax expense160 133 96 
Increase (decrease) in tax expense resulting from:
State income tax expense, net of federal income tax27 13 18 
Excess deferred income tax amortization(17)(18)(41)
Other, net(2)(3)3 
Total8 (8)(20)
Total income tax expense$168 $125 $76 
Effective tax rate22 %20 %17 %
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Year Ended December 31,Year Ended December 31,
2023202320222021
(in millions)(in millions)
CERC - Continuing Operations (8) (9) (10)
Income before income taxes
Income before income taxes
Income before income taxes
Federal statutory income tax rateFederal statutory income tax rate21 %21 %21 %
Expected federal income tax expense
Increase (decrease) in tax expense resulting from:
State income tax expense, net of federal income tax
State income tax expense, net of federal income tax
State income tax expense, net of federal income tax
State law change, net of federal income tax
State valuation allowance, net of federal income tax
Goodwill impairment
Goodwill impairment
Goodwill impairment
Excess deferred income tax amortization
Other, net
Other, net
Other, net
Total
Total income tax expense (benefit)
Effective tax rateEffective tax rate(5)%25 %16 %
Year Ended December 31,
2017 2016 2015
(in millions)
Income (loss) before income taxes$1,063
 $686
 $(1,130)
Federal statutory income tax rate35 % 35% 35%
Expected federal income tax expense (benefit)372
 240
 (396)
Increase (decrease) in tax expense resulting from: 
  
  
State income tax expense, net of federal income tax26
 27
 (27)
State valuation allowance, net of federal income tax3
 3
 —
Federal income tax rate reduction(1,113) —
 —
Other, net(17) (16) (15)
Total(1,101) 14
 (42)
Total income tax expense (benefit)$(729) $254
 $(438)
Effective tax rate(69)% 37% 39%


In 2017, CenterPoint Energy recognized(1)Recognized a $1.1 billion deferred tax$69 million benefit fromfor the impact of state apportionment changes that resulted in the remeasurement of CenterPoint Energy’s ADFITstate deferred taxes of the unitary group, a $44 million benefit for the amortization of the net regulatory EDIT liability as decreed by regulators in certain jurisdictions, a result$13 million benefit for the impact of AFUDC equity, and a $28 million expense for the gain on the Energy Systems Group sale.
(2)Recognized a $51 million benefit for the amortization of the enactmentnet regulatory EDIT liability as decreed by regulators in certain jurisdictions, an $8 million benefit for the impact of AFUDC equity, and a $84 million expense for the goodwill impairment on the Arkansas and Oklahoma Natural Gas business sale.
(3)Recognized a $75 million benefit for the amortization of the TCJA on December 22, 2017 which reducednet regulatory EDIT liability as decreed by regulators in certain jurisdictions, a $23 million benefit for the U.S. corporate income tax rate from 35% to 21%. For additional information onimpact of state law changes that resulted in the 2017 impactsremeasurement of the TCJA, please see the discussion following thestate deferred tax assets and liabilities table below.

In 2016, CenterPoint Energy recognizedtaxes in those jurisdictions, a $6 million deferred tax expense duebenefit for the impact of AFUDC equity, and a $15 million benefit for the impact of a change in the NOL carryforward period in Louisiana from 20 years to Louisiana state law change and recorded an additional $3 millionindefinite period allowing for the release of the valuation allowance on certain Louisiana NOLs.
(4)Recognized a $27 million benefit for the impact of state carryforwards.law changes that resulted in the remeasurement of state deferred taxes in those jurisdictions.

(5)Recognized a $17 million benefit for the amortization of the net regulatory EDIT liability as decreed by regulators in certain jurisdictions.
In 2015, CenterPoint Energy’s effective tax rate was higher than(6)Recognized a $18 million benefit for the statutory rate primarily dueamortization of the net regulatory EDIT liability as decreed by regulators in certain jurisdictions.
(7)Recognized a $41 million benefit for the amortization of the net regulatory EDIT liability as decreed by regulators in certain jurisdictions.
(8)Recognized a $66 million benefit for the impact of state apportionment changes that resulted in the remeasurement of state deferred taxes of the unitary group, and a $23 million benefit for the amortization of the net regulatory EDIT liability as decreed by regulators in certain jurisdictions.
(9)Recognized a $28 million benefit for the amortization of the net regulatory EDIT liability as decreed by regulators in certain jurisdictions, and a $30 million expense for the goodwill impairment on the Arkansas and Oklahoma Natural Gas business sale.
(10)Recognized a $9 million benefit for the impact of state law changes that resulted in the remeasurement of state deferred taxes in those jurisdictions, a $30 million benefit for the amortization of the net regulatory EDIT liability as decreed by regulators in certain jurisdictions, and a $15 million benefit for the impact of a change in the NOL carryforward period in Louisiana from 20 years to lower earnings froman indefinite period allowing for the impairmentrelease of CenterPoint Energy’s equity method investment in Enable. The impairment loss reduced the deferred tax liabilityvaluation allowance on CenterPoint Energy’s equity method investment in Enable.certain Louisiana NOLs.



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The tax effects of temporary differences that give rise to significant portions of deferred tax assets and liabilities were as follows:
December 31,
20232022
(in millions)
CenterPoint Energy
Deferred tax assets:
Benefits and compensation$131 $121 
Regulatory liabilities365 378 
Loss and credit carryforwards76 84 
Asset retirement obligations96 95 
Other124 49 
Valuation allowance(10)(10)
Total deferred tax assets782 717 
Deferred tax liabilities:
Property, plant and equipment3,580 3,228 
Regulatory assets401 601 
Investment in ZENS and equity securities related to ZENS788 722 
Other92 152 
Total deferred tax liabilities4,861 4,703 
Net deferred tax liabilities$4,079 $3,986 
Houston Electric
Deferred tax assets:
Benefits and compensation$10 $10 
Regulatory liabilities176 184 
Asset retirement obligations6 6 
Other18 13 
Total deferred tax assets210 213 
Deferred tax liabilities:
Property, plant and equipment1,497 1,330 
Regulatory assets119 112 
Total deferred tax liabilities1,616 1,442 
Net deferred tax liabilities$1,406 $1,229 
CERC
Deferred tax assets:
Benefits and compensation$21 $9 
Regulatory liabilities145 151 
Loss and credit carryforwards276 466 
Asset retirement obligations86 86 
Other65 25 
Total deferred tax assets593 737 
Deferred tax liabilities:
Property, plant and equipment1,602 1,427 
Regulatory assets171 381 
Other66 191 
Total deferred tax liabilities1,839 1,999 
Net deferred tax liabilities$1,246 $1,262 
 December 31,
 2017 2016
 (in millions)
Deferred tax assets:   
Benefits and compensation$162
 $316
Regulatory liabilities347
 57
Loss and credit carryforwards90
 79
Asset retirement obligations68
 77
Other16
 21
Valuation allowance(7) (5)
Total deferred tax assets676
 545
Deferred tax liabilities: 
  
Property, plant, and equipment1,808
 2,603
Investment in unconsolidated affiliates927
 1,383
Regulatory assets473
 940
Investment in marketable securities and indexed debt502
 772
Indexed debt securities derivative13
 4
Other127
 106
Total deferred tax liabilities3,850
 5,808
Net deferred tax liabilities$3,174
 $5,263


Federal Tax Reform. On December 22, 2017, President Trump signed into law comprehensive tax reform legislation informally called the Tax Cuts and Jobs Acts, or TCJA, which resulted in significant changes to federal tax laws effective January 1, 2018.  The new legislation contains several key tax provisions that will impact CenterPoint Energy, including the reduction of the corporate income tax rate from 35% to 21% effective January 1, 2018. The new legislation also includes a variety of other changes, such as, a limitation on the tax deductibility of interest expense, acceleration of business asset expensing and reduction in the amount of executive pay that may qualify for a tax deduction, among others. Several other provisions of the TCJA are not generally applicable to the public utility industry, including the limitation on the tax deductibility of interest expense and the acceleration of business asset expensing.

While the effective date of the rate change in the legislation is January 1, 2018, ASC 740 requires that deferred tax balances be adjusted in the period of enactment to the rate in which those deferred taxes will reverse. The EDIT from the rate change resulted in an adjustment to income tax expense of approximately $1.1 billion and creation of a net regulatory liability of $1.3 billion (includes $0.3 billion gross-up) for the amount that is likely to be returned to ratepayers. The major components of the $1.1 billion benefit to income tax expense are for the remeasurement of CenterPoint Energy's deferred taxes associated with its investment in Enable, investment in marketable securities (ZENS) and stranded costs related to the Securitization Bonds. The amount and expected amortization of the net regulatory tax liability may differ from the $1.3 billion estimate, possibly materially, due to, among other things, regulatory actions, interpretations and assumptions CenterPoint Energy has made, and any guidance that may be issued in the future. CenterPoint Energy will continue to assess the amount and expected amortization of the net regulatory tax liability as it has proceedings with regulators in future periods. For the discussion of risks associated with the amount and expected flow through of EDIT by Houston Electric and NGD, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Regulatory Matters —Tax Reform” in Item 7 of Part II of this report.

Tax Attribute Carryforwards and Valuation Allowance. Allowance.  CenterPoint Energy has no remaining federal net operating loss carryforward orNOL carryforwards and no federal tax creditscharitable contribution carryforwards as of December 31, 2017.2023. As of December 31, 2017,2023, CenterPoint Energy had $870 million$1 billion of state net operating lossNOL carryforwards that expire between 20182024 and 20372042, and $12$2 million of state tax credits, thatnet of valuation allowance, which do not expire. A state capital loss carryforward of $244 million expired unutilized at the end of 2017. CenterPoint Energy reported a valuation allowance of $7 millionagainst certain state NOL and credit carryforwards because it is more likely than not that the benefit from certain state net operating loss carryforwards will not be realized.



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CERC has $931 million of federal NOL carryforwards which have an indefinite carryforward period. CERC has $657 million of gross state NOL carryforwards which expire between 2024 and 2042, and $2 million of state tax credits, net of valuation allowance, which do not expire.
Uncertain Income Tax Positions.
A reconciliation of CenterPoint Energy reported no uncertainEnergy’s beginning and ending balance of unrecognized tax liabilitybenefits, excluding interest and penalties, for 2023 and 2022 are as follows:
Year Ended December 31,
20232022
(in millions)
Balance, beginning of year$26 $3 
   Increases related to tax positions of prior years— 26 
   Decreases related to tax positions of prior years— (3)
   Lapse of statute of limitations(1)— 
Balance, end of year$25 $26 

CenterPoint Energy’s net unrecognized tax benefits, including penalties and interest, were $29 million as of December 31, 2017, 20162023 and 2015. CenterPoint Energy expects no significant change toare included in other non-current liabilities in the Consolidated Financial Statements. Included in the balance of uncertain tax liability overpositions as of December 31, 2023 are $25 million of tax benefits that, if recognized, would affect the effective tax rate. The Registrants recognize interest accrued related to unrecognized tax benefits and penalties as income tax expense. The above table does not include $4 million of accrued penalties and interest as of December 31, 2023. The Registrants believe that it is reasonably possible that there will be a $3 million decrease in unrecognized tax benefits, including penalties and interest, in the next 12 months ending December 31, 2018.as a result of a lapse of statutes on older exposures, a tax settlement, and/or a resolution of open audits.


Tax Audits and Settlements.Settlements. Tax years through 20152018 and tax year 2021 have been audited and settled with the IRS.IRS for CenterPoint Energy. Tax years 2019-2020 remain open. For the 2016 through 20182019-2023 tax years, CenterPoint Energy is a participantthe Registrants are participants in the IRS’s Compliance Assurance Process. Vectren’s pre-Merger 2014-2019 tax years have been audited and settled with the IRS.


(15) Commitments and Contingencies


(a) Natural Gas SupplyPurchase Obligations (CenterPoint Energy and Other CommitmentsCERC)


Natural gas supply commitmentsCommitments include natural gas contractsminimum purchase obligations related to CenterPoint Energy’s and CERC’s Natural Gas Distributionreportable segment and Energy Services business segments, whichCenterPoint Energy’s Electric reportable segment. A purchase obligation is defined as an agreement to purchase goods or services that is enforceable and legally binding on the registrant and that specifies all significant terms, including: fixed or minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transaction. Contracts with minimum payment provisions have various quantity requirements and durations thatand are not classified as non-trading derivative assets and liabilities in CenterPoint Energy’s and CERC’s Consolidated Balance Sheets as of December 31, 20172023 and 2016 as these2022. These contracts meet an exception as “normal purchases contracts” or do not meet the definition of a derivative. Natural gas and coal supply commitments also include natural gas transportation contracts that do not meet the definition of a derivative.

On February 1, 2023, Indiana Electric entered into an amended and restated BTA to purchase the 191 MW Posey Solar project for a fixed purchase price over the anticipated 35-year life. 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 filed the updated CPCN with a request that project costs, net of PTCs, be recovered in rate base, through base rates or the CECA mechanism, depending on which provides more timely recovery. 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.

On January 11, 2023, the IURC issued an order approving the settlement agreement granting Indiana Electric a CPCN to purchase and acquire the 130 MW Pike County solar project through a BTA and approved the estimated cost. The IURC also designated the project as a clean energy project as well as approved the proposed levelized rate and associated ratemaking and accounting treatment. Due to inflationary pressures, the developer disclosed that costs have exceeded the agreed upon levels in the BTA. Once pricing is updated and parties determine whether to continue with the project, Indiana Electric may have to refile for approval of the project with the IURC, which could delay the in-service date from 2025 to 2026. If Indiana Electric is not able to reach a mutually acceptable solution with the developers of the Pike County Solar project, Indiana Electric may seek to terminate the project.
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As of December 31, 2017,2023, other than discussed below, undiscounted minimum purchase obligations are approximately:
CenterPoint EnergyCERC
Natural Gas Supply
Electric Supply (1)
Other (2)
Natural Gas Supply
(in millions)
2024$684 $145 $164 $679 
2025589 478 45 585 
2026502 342 46 498 
2027425 105 4 422 
2028380 68 — 377 
2029 and beyond1,707 737 328 1,684 
(1)CenterPoint Energy’s undiscounted minimum payment obligations for natural gas supplyrelated to PPAs with commitments ranging from 15 years to 25 years and other commitmentsits purchase commitment under its BTA in Posey County, Indiana at the original contracted amount, prior to any renegotiation, and its BTA in Pike County, Indiana, are approximately:included above.
 Natural Gas Supply 
Other (1)
 (in millions)
2018$463
 $37
2019353
 17
2020169
 11
202179
 —
202249
 —
2023 and beyond108
 —

(1)Primarily relates(2)The undiscounted payment obligations relate primarily to technology hardware and software agreements.

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

(b) AMAs (CenterPoint Energy and CERC)


NGD currently hasCenterPoint Energy’s and CERC’s Natural Gas businesses continue to utilize AMAs associated with itstheir utility distribution service in Arkansas,Indiana, Louisiana, Minnesota, Mississippi Oklahoma and Texas. The AMAs have varying terms, the longest of which expires in 2020.2029. Pursuant to the provisions of the agreements, CenterPoint Energy’s and CERC’s Natural Gas either sells natural gas to the asset manager and agrees to repurchase an equivalent amount of natural gas throughout the year at the same cost, or simply purchases its full natural gas requirements at each delivery point from the asset manager. Generally, AMAs are contracts between NGDCenterPoint Energy’s and CERC’s Natural Gas and an asset manager that are intended to transfer the working capital obligation and maximize the utilization of the assets. In these AMAs, NGDagreements, CenterPoint Energy’s and CERC’s Natural Gas agrees to release transportation and storage capacity to other parties to manage natural gas storage, supply and delivery arrangements for NGDCenterPoint Energy’s and CERC’s Natural Gas and to use the released capacity for other purposes when it is not needed for NGD. NGD is compensated byCenterPoint Energy’s and CERC’s Natural Gas. CenterPoint Energy’s and CERC’s Natural Gas may receive compensation from the asset manager through payments made over the life of the AMAs based in part on the results of the asset optimization. NGDAMAs. CenterPoint Energy’s and CERC’s Natural Gas has an obligation to purchase itstheir winter storage requirements that have been released to the asset manager under these AMAs. NGD has received approval fromFor amounts outstanding under these AMAs, see Note 13.

(c) Guarantees and Product Warranties (CenterPoint Energy)

On May 21, 2023, CenterPoint Energy, through Vectren Energy Services, entered into the state regulatory commissions in Arkansas, Louisiana, Mississippi and OklahomaEquity Purchase Agreement to retain a sharesell Energy Systems Group. The sale closed on June 30, 2023. See Note 4 for further information.

In the normal course of business prior to the consummation of the AMA proceeds.

(c) Lease Commitments

The following table sets forth information concerningtransaction on June 30, 2023, CenterPoint Energy’sEnergy, primarily through Vectren, issued parent company level guarantees supporting Energy Systems Group’s obligations. When Energy Systems Group was wholly owned by CenterPoint Energy, these guarantees did not represent incremental consolidated obligations, but rather, these guarantees represented guarantees of Energy Systems Group’s obligations to allow it to conduct business without posting other forms of assurance. For those obligations where potential exposure can be estimated, management estimates the maximum exposure under non-cancelable long-term operating leasesthese guarantees to be approximately $503 million as of December 31, 2017,2023 and expects the exposure to decrease pro rata. This exposure primarily relates to energy savings guarantees on federal energy savings performance contracts. Other parent company level guarantees, certain of which primarily consistdo not contain a cap on potential liability, were issued prior to the sale of rental agreementsEnergy Systems Group in support of federal operations and maintenance projects for building space, data processing equipment, compression equipmentwhich a maximum exposure cannot be estimated based on the nature of the projects.

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Under the terms of the Equity Purchase Agreement, ESG Holdings Group must generally use reasonable best efforts to replace existing CenterPoint Energy guarantees with credit support provided by a party other than CenterPoint Energy as of and rights-of-way:after the closing of the transaction. The Equity Purchase Agreement also requires certain protections to be provided for any damages incurred by CenterPoint Energy in relation to these guarantees not released by closing. No additional guarantees were provided by CenterPoint Energy in favor of Energy Systems Group subsequent to the closing of the sale on June 30, 2023.

 (in millions)
2018$5
20195
20204
20214
20223
2023 and beyond5
Total$26
While there can be no assurance that performance under any of these parent company guarantees will not be required in the future, CenterPoint Energy considers the likelihood of a material amount being incurred as remote. CenterPoint Energy believes that, from Energy Systems Group’s inception in 1994 to the closing of the sale of Energy Systems Group on June 30, 2023, Energy Systems Group had a history of generally meeting its performance obligations and energy savings guarantees and its installed products operated effectively. CenterPoint Energy recorded no amounts on its Consolidated Balance Sheets as of December 31, 2023 and December 31, 2022 related to its obligation under the outstanding guarantees.



Total lease expense for all operating leases was $10 million, $10 million and $9 million during 2017, 2016 and 2015, respectively.


(d) Legal, Environmental and Other Matters


Legal Matters


Gas Market Manipulation Cases.Litigation Related to the February 2021 Winter Storm Event. Various legal proceedings are still pending against numerous entities with respect to the February 2021 Winter Storm Event, including against CenterPoint Energy, Utility Holding, LLC, Houston Electric, or their predecessor, Reliantand CERC. Like other Texas energy companies and TDUs, CenterPoint Energy and Houston Electric have become involved in certain investigations, litigation and other regulatory and legal proceedings regarding their efforts to restore power during the storm and their compliance with NERC, ERCOT and PUCT rules and directives. Additionally, like other natural gas market participants, CERC has been named in litigation alleging gas market manipulation.

CenterPoint Energy, Utility Holding, LLC, and Houston Electric, along with hundreds of their former subsidiariesother defendants (including ERCOT, power generation companies, other TDUs, natural gas producers, REPs, and other entities) have received claims and lawsuits filed by plaintiffs alleging wrongful death, personal injury, property damage and other injuries and damages. As of December 31, 2023, there are approximately 220 pending lawsuits that are consolidated in Texas state court in Harris County, Texas, as part of the MDL proceeding related to the February 2021 Winter Storm Event, and CenterPoint Energy and Houston Electric, along with numerous other entities, have been named as defendants in certainapproximately 155 of those lawsuits. One of the lawsuits described below. Underin the MDL is a master separation agreementputative class action on behalf of everyone who received electric power via ERCOT grid and sustained a power outage between February 10, 2021 and February 28, 2021. Additionally, Utility Holding, LLC is currently named as a defendant in one lawsuit in which CenterPoint Energy and Houston Electric are also named as defendants.

The judge overseeing the MDL issued an initial case management order and stayed all proceedings and discovery. Per the case management order, the judge entertained dispositive motions in fiverepresentative or “bellwether” cases and, in late January 2023, issued rulings on them. In a former subsidiary, RRI,recent opinion in an unrelated matter, the Texas Supreme Court held that ERCOT is entitled to sovereign immunity. This ruling will apply to claims against ERCOT in the MDL. The MDL judge also dismissed all claims against the natural gas defendants (which list of natural gas defendants incorrectly included Utility Holding, LLC) and the REP defendants and some causes of action against the other defendants. CenterPoint Energy expects that the claims against Utility Holding, LLC will ultimately be dismissed in light of the judge’s initial rulings. As to the TDU and generator defendants, the judge dismissed some causes of action but denied the motions to dismiss claims for negligence, gross negligence, and nuisance, which denial the TDU defendants and generator defendants asked the courts of appeals to overturn. A three-judge panel of the Court of Appeals for the Fourteenth District of Texas heard oral argument in the TDU mandamus proceeding on October 23, 2023. An opinion in that proceeding has not yet been issued. On December 14, 2023, a three-judge panel of the Court of Appeals for the First District of Texas issued an opinion in the generator mandamus proceeding, granting the generators’ mandamus request and ordering that plaintiffs’ remaining claims against the generators be dismissed. The plaintiffs are expected to seek rehearing before the entire First Court of Appeals of that panel’s ruling. The MDL judge is allowing defendants (including Houston Electric) to file several additional motions on preliminary legal issues, and otherwise the cases remain stayed. CenterPoint Energy, Utility Holding, LLC, and Houston Electric intends to vigorously defend themselves against the claims raised.
CenterPoint Energy and Houston Electric have also responded to inquiries from the Texas Attorney General and the Galveston County District Attorney’s Office, and various other regulatory and governmental entities also conducted inquiries, investigations and other reviews of the February 2021 Winter Storm Event and the efforts made by various entities to prepare for, and respond to, the event, including the electric generation shortfall issues.

In February 2023, twelve lawsuits were filed in state district court in Harris County and Tom Green County, Texas, against dozens of gas market participants in Texas, including natural gas producers, processors, pipelines, marketers, sellers, traders,
158

gas utilities, and financial institutions. Plaintiffs named CERC as a defendant, along with “CenterPoint Energy Services, Inc.,” incorrectly identifying it as CERC’s parent company (CenterPoint Energy previously divested CES). One lawsuit filed in Harris County is a putative class action on behalf of two classes of electric and natural gas customers (those who experienced a loss of electricity and/or natural gas, and those who were charged securitization-related surcharges on a utility bill or were otherwise charged higher rates for electricity and/or gas during the February 2021 Winter Storm Event), potentially including millions of class members. Two other lawsuits (one filed in Harris County and one in Tom Green County) are brought by an entity that purports to be an assignee of claims by tens of thousands of persons and entities that have assigned claims to the plaintiff. These, and nine other similar lawsuits filed in Harris County, generally allege that the defendants engaged in gas market manipulation and price gouging, including by intentionally withholding, suppressing, or diverting supplies of natural gas in connection with the February 2021 Winter Storm Event, Winter Storm Elliott, and other severe weather conditions, and through financial market manipulation. Plaintiffs allege that this manipulation impacted gas supply and prices as well as the market, supply, and price of electricity in Texas and caused blackouts and other damage. Plaintiffs assert claims for tortious interference with existing contract, private nuisance, and unjust enrichment, and allege a broad array of injuries and damages, including personal injury, property damage, and harm from certain costs being securitized and passed on to ratepayers. The lawsuits do not specify the amount of damages sought, but seek broad categories of actual, compensatory, statutory, consequential economic, and punitive damages; restitution and disgorgement; pre- and post-judgment interest; costs and attorneys’ fees; and other relief. As of December 31, 2023, most of the lawsuits have not been served, but the three cases in which defendants were served were tagged for transfer to the existing MDL proceeding referenced above. The plaintiffs in those three cases filed motions to remand the lawsuits back to their original trial courts and out of the MDL. On August 1, 2023, the judge overseeing the MDL denied the motions to remand. On November 29, 2023, the MDL panel denied Plaintiffs’ joint motion for reconsideration of the MDL judge’s orders denying remand, and the time to appeal the MDL panel’s decision has passed. These lawsuits remain pending in the MDL, and CERC intends to vigorously defend itself against the claims raised, including by raising jurisdictional challenges to the plaintiffs’ claims. The nine other similar lawsuits filed in Harris County have also been tagged for transfer to the MDL proceeding, but the defendants, including CERC, have not been served. These gas market cases are in addition to the 220 cases noted above regarding electric market issues.

To date, there have not been demands, quantification, disclosure or discovery of damages by any party to any of the above legal matters that are sufficient to enable CenterPoint Energy and its subsidiaries to estimate exposure. Given that, as well as the preliminary nature of the proceedings, the numerosity of parties and complexity of issues involved, and the uncertainties of litigation, CenterPoint Energy and its subsidiaries are entitledunable to be indemnified by RRI and its successors forpredict the outcome or consequences of any losses, including certain attorneys’ fees and other costs, arising out of these lawsuits.  In May 2009, RRI sold its Texas retail business to a subsidiary of NRG and RRI changed its name to RRI Energy, Inc. In December 2010, Mirant Corporation merged with and became a wholly-owned subsidiary of RRI, and RRI changed its name to GenOn. In December 2012, NRG acquired GenOn through a merger in which GenOn became a wholly-owned subsidiary of NRG. None of the saleforegoing matters or to estimate a range of the retail business, the merger with Mirant Corporation, or the acquisition of GenOn by NRG alters RRI’s (now GenOn’s) contractual obligations to indemnifypotential losses. CenterPoint Energy and its subsidiaries including Houston Electric, for certain liabilities, including their indemnification obligations regarding the gas market manipulation litigation.

A large number of lawsuits were filed against numerous gas market participants in a number of federal and western state courts in connection with the operation of the natural gas markets in 2000–2002. CenterPoint Energy and its affiliates have since been released or dismissed from all such cases. CES, a subsidiary of CERC Corp., was a defendant in a case now pending in federal court in Nevada alleging a conspiracy to inflate Wisconsin natural gas prices in 2000–2002. On May 24, 2016, the district court granted CES’s motion for summary judgment, dismissing CES from the case. The plaintiffs have appealed that ruling. CenterPoint Energy and CES intend to continue vigorously defending against the plaintiffs’ claims. In June 2017, GenOn and various affiliates filed for protection under Chapter 11 of the U.S. Bankruptcy Code. In December 2017, GenOn received court approval of a restructuring plan and is expected to emerge from Chapter 11 in mid-2018. CenterPoint Energy, CERC, and CES submitted proofs of claim in the bankruptcy proceedings to protect their indemnity rights. If GenOn were unable to meet its indemnity obligations or satisfy a liability that has been assumed in the gas market manipulation litigation, then CenterPoint Energy, Houston Electric or CERC could incur liability and be responsible for satisfying the liability. CenterPoint Energy does not expect the ultimate outcome of the case against CES to have a material adverse effect on its financial condition, results of operations or cash flows.

Minnehaha Academy.  On August 2, 2017, a natural gas explosion occurred at the Minnehaha Academy in Minneapolis, Minnesota, resulting in the deaths of two school employees, serious injuries to others and significant property damage to the school.  CenterPoint Energy, certain of its subsidiaries, and the contractor company working in the school have been named in litigation arising out of this incident.  Additionally, CenterPoint Energy is cooperating with the ongoing investigation conducted by the National Transportation Safety Board. Further, CenterPoint Energy is contesting approximately $200,000 in fines imposed by the Minnesota Office of Pipeline Safety.  In early 2018, the Minnesota Occupational Safety and Health Administration concluded its investigation without any adverse findings against CenterPoint Energy. CenterPoint Energy’s general and excess liability insurance policies that provide coverage for third-party bodily injury and property damage claims. As CenterPoint Energy previously noted, given the nature of certain of the plaintiffs’ allegations, insurance coverage may not be available other than for third party bodily injury and property damage claims. claims caused by an accident, and one of CenterPoint Energy’s insurers recently denied coverage for intentional injury as alleged by plaintiffs in the gas market cases. CenterPoint Energy and its subsidiaries intend to continue to pursue any and all available insurance coverage for all of these matters.


Jefferson Parish. Several parishes and the State of Louisiana filed 42 suits under Louisiana’s State and Local Coastal Resources Management Act (SCLRMA) against hundreds of oil and gas companies seeking compensatory damages for contamination and erosion of the Louisiana coastline allegedly caused by historical oil and gas operations. One of the defendants in one of the lawsuits (filed in 2013 only by the Parish of Jefferson) is Primary Fuels, Inc., a predecessor company of CenterPoint Energy, which operated in Louisiana from 1983-1989. All 42 suits were removed to Louisiana federal courts twice and were stayed for several years pending the district courts’ consideration of various motions to remand and multiple appeals of remand orders. Recently, several cases involving other parishes that had been remanded to Louisiana state court have begun to resume proceedings in state court. However, as of December 31, 2023, the federal district court had not ruled on Jefferson Parish’s motion to remand to state court the lawsuit which includes Primary Fuels among the defendants.

Because of the procedurally preliminary nature of the proceedings, lack of information about both the scope of and damages for Jefferson Parish’s claim against Primary Fuels, the numerosity of parties and complexity of issues involved, and the uncertainties of litigation, CenterPoint Energy and its subsidiaries are unable to predict the outcome or consequences of this matter or to estimate a range of potential losses. CenterPoint Energy will continue to vigorously defend itself against the claims raised and pursue any and all available insurance coverage.

Environmental Matters


MGP Sites. CenterPoint Energy, CERC and itstheir predecessors, including predecessors of Vectren, operated MGPs in the past. The costs CenterPoint Energy or CERC, as applicable, expect to incur to fulfill their respective obligations are estimated by management using assumptions based on actual costs incurred, the timing of expected future payments and inflation factors, among others. While CenterPoint Energy and CERC have recorded obligations for all costs which are probable and estimable, including amounts they are presently obligated to incur in connection with activities at these sites, it is possible that future
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events may require remedial activities which are not presently foreseen, and those costs may not be subject to PRP or insurance recovery.

(i)Minnesota MGPs (CenterPoint Energy and CERC). With respect to certain Minnesota MGP sites, CenterPoint Energy and CERC hashave completed state-ordered remediation and continuescontinue state-ordered monitoring and water treatment. As of December 31, 2017,CenterPoint Energy and CERC hadrecorded a recorded liability of $7 millionas reflected in the table below for continued monitoring and any future remediation required by regulators in Minnesota.

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

(iii)Other MGPs(CenterPoint Energy and CERC). In addition to the Minnesota and Indiana sites, the EPA and other regulators have investigated MGP sites that were owned or operated by CenterPoint Energy or CERC or may have been owned by one of their former affiliates.

Total costs that may be incurred in connection with addressing these sites cannot be determined at this time. The estimated accrued costs are limited to CenterPoint Energy’s and CERC’s share of the remediation efforts and are therefore net of exposures of other PRPs. The estimated range of possible remediation costs for the sites for which CenterPoint Energy and CERC believes itbelieve they may have responsibility was $5 million to $30 million based on remediation continuing for 30 to 50 years. the minimum time frame given in the table below.
December 31, 2023
CenterPoint EnergyCERC
(in millions, except years)
Amount accrued for remediation$13 $11 
Minimum estimated remediation costs8 7 
Maximum estimated remediation costs51 44 
Minimum years of remediation55
Maximum years of remediation5050

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


In addition to the Minnesota sites, the EPA and other regulators have investigated MGP sites that were owned or operated by CERC or may have been owned by one of its former affiliates. CenterPoint Energy doesand CERC do not expect the ultimate outcome of these matters to have a material adverse effect on the financial condition, results of operations or cash flows of either CenterPoint Energy or CERC.


Asbestos.Some facilities owned by CenterPoint Energythe Registrants or itstheir predecessors in interest contain or have contained asbestos insulation and other asbestos-containing materials. CenterPoint Energy and its subsidiariesThe Registrants are from time to time named, along


with numerous others, as defendants in lawsuits filed by a number of individuals who claim injury due to exposure to asbestos, and CenterPoint Energy anticipatesthe Registrants anticipate that additional claims may be asserted in the future. Although their ultimate outcome cannot be predicted at this time, CenterPoint Energy doesthe Registrants do not expect these matters, either individually or in the aggregate, to have a material adverse effect on CenterPoint Energy’stheir financial condition, results of operations or cash flows.


CCR Rule (CenterPoint Energy). In April 2015, the EPA finalized its CCR Rule, which regulates ash as non-hazardous material under the RCRA. The final rule allows beneficial reuse of ash, and the majority of the ash generated by Indiana Electric’s generating plants will continue to be reused. In July 2018, the EPA released its final CCR Rule Phase I Reconsideration which extended the deadline to October 31, 2020 for ceasing placement of ash in ponds that exceed groundwater protections standards or that fail to meet location restrictions. In August 2019, the EPA proposed additional “Part A” amendments to its CCR Rule with respect to beneficial reuse of ash and other materials. The Part A amendments were finalized in August 2020 and extended the deadline to cease placement of ash in ponds to April 11, 2021, discussed further
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below. The Part A amendments do not restrict Indiana Electric’s current beneficial reuse of its fly ash. On May 18, 2023, the EPA issued a proposed revision to the CCR rule that could potentially expand the scope of units regulated under the federal CCR rule (the CCR “Legacy” rule). The CCR Legacy rule seeks to include legacy CCR surface impoundments (inactive surface impoundments at inactive generating facilities) as well as new “CCR management units” at active or inactive facilities otherwise subject to federal CCR regulations. The potential impact of the CCR Legacy rule is uncertain at this time, and if finalized could require Registrant to conduct additional CCR investigations.

Indiana Electric has three ash ponds, two at the F.B. Culley facility (Culley East and Culley West) and one at the A.B. Brown facility. Under the existing CCR Rule, Indiana Electric is required to perform integrity assessments, including ground water monitoring, at its F.B. Culley and A.B. Brown generating stations. The ground water studies were necessary to determine the remaining service life of the ponds and whether a pond must be retrofitted with liners or closed in place. Indiana Electric’s Warrick generating unit is not included in the scope of the CCR Rule as this unit has historically been part of a larger generating station that predominantly serves an adjacent industrial facility. Groundwater monitoring indicates potential groundwater impacts adjacent to Indiana Electric’s ash impoundments, and further analysis is ongoing. The CCR Rule required companies to complete location restriction determinations by October 18, 2018. Indiana Electric completed its evaluation and determined that one F.B. Culley pond (Culley East) and the A.B. Brown pond fail the aquifer placement location restriction. As a result of this failure, Indiana Electric was required to cease disposal of new ash in the ponds and commence closure of the ponds by April 11, 2021, unless approved for an extension. CenterPoint Energy filed timely extension requests available under the CCR Rule that would allow Indiana Electric to continue to use the ponds through October 15, 2023. On October 5, 2022, the EPA issued a proposed conditional approval of the Part A extension request for the A.B. Brown pond. Both the Culley East and A.B. Brown facility have been taken out of service in a timely manner per the commitments made to the EPA in the extension requests filed for both ponds. On April 24, 2019, Indiana Electric received an order from the IURC approving recovery in rates of costs associated with the closure of the Culley West pond, which has already completed closure activities. On August 14, 2019, Indiana Electric filed its petition with the IURC for recovery of costs associated with the closure of the A.B. Brown ash pond, which would include costs associated with the excavation and recycling of ponded ash. This petition was subsequently approved by the IURC on May 13, 2020. On October 28, 2020, the IURC approved Indiana Electric’s ECA proceeding, which included the initiation of recovery of the federally mandated project costs.

On November 1, 2022, Indiana Electric filed for a CPCN to recover federally mandated costs associated with closure of the Culley East Pond, its third and final ash pond. Indiana Electric is also seeking accounting and ratemaking relief for the project, and on June 8, 2023, Indiana Electric filed a revised CPCN for recovery of the federally mandated ash pond costs. The project costs are estimated to be approximately $52 million, inclusive of overheads.

In July 2018, Indiana Electric filed a Complaint for Damages and Declaratory Relief against its insurers seeking reimbursement of defense, investigation and pond closure costs incurred to comply with the CCR Rule, and has since reached confidential settlement agreements with its insurers. The proceeds of these settlements will offset costs that have been and will be incurred to close the ponds.

As of December 31, 2023, CenterPoint Energy has recorded an approximate $116 million ARO, which represents the discounted value of future cash flow estimates to close the ponds at A.B. Brown and F.B. Culley. This estimate is subject to change due to the contractual arrangements; continued assessments of the ash, closure methods, and the timing of closure; implications of Indiana Electric’s generation transition plan; changing environmental regulations; and proceeds received from the settlements in the aforementioned insurance proceeding. In addition to these AROs, Indiana Electric also anticipates equipment purchases of between $60 million and $80 million to complete the A.B. Brown closure project.

Clean Water Act Permitting of Groundwater Discharges. In April 2020, the U.S. Supreme Court issued an opinion providing that indirect discharges via groundwater or other non-point sources are subject to permitting and liability under the Clean Water Act when they are the functional equivalent of a direct discharge. On November 27, 2023, the EPA published draft guidance regarding the application of the “functional equivalent” analysis as related to permitting of certain discharges through groundwater to surface waters. The Registrants are evaluating the extent to which this decision and the proposed EPA guidance will affect Clean Water Act permitting requirements and/or liability for their operations.

Other Environmental. From time to time, CenterPoint Energy identifiesthe Registrants identify the presence of environmental contaminants during its operations or on property where its predecessor companiestheir predecessors have conducted operations. Other such sites involving contaminants may be identified in the future. CenterPoint Energy hasThe Registrants have and expectsexpect to continue to remediate any identified sites consistent with its state and federal legal obligations. From time to time, CenterPoint Energy hasthe Registrants have received notices, and may receive notices in the future, from regulatory authorities or others regarding its status as a PRP in connection with sites found to require remediation due to the presence of environmental contaminants. In addition, CenterPoint Energy hasthe Registrants have been, or may be, named from time to time as a defendantdefendants in litigation related to such sites. Although the ultimate outcome of such matters cannot be predicted at this time, CenterPoint Energy doesthe
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Registrants do not expect these matters, either individually or in the aggregate, to have a material adverse effect on CenterPoint Energy’stheir financial condition, results of operations or cash flows.


Other Proceedings


CenterPoint Energy isThe Registrants are involved in other legal, environmental, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business. From time to time, CenterPoint Energy isthe Registrants are also a defendantdefendants in legal proceedings with respect to claims brought by various plaintiffs against broad groups of participants in the energy industry. Some of these proceedings involve substantial amounts. CenterPoint EnergyThe Registrants regularly analyzesanalyze current information and, as necessary, providesprovide accruals for probable and reasonably estimable liabilities on the eventual disposition of these matters. CenterPoint Energy doesThe Registrants do not expect the disposition of these matters to have a material adverse effect on CenterPoint Energy’sthe Registrants’ financial condition, results of operations or cash flows.


(16) Earnings Per Share (CenterPoint Energy)


Basic earnings per common share is computed by dividing income available to common shareholders from continuing operations by the weighted average number of common shares outstanding during the period. Participating securities are excluded from weighted average number of common shares outstanding in the computation of basic earnings per common share. Diluted earnings per common share is computed by dividing income available to common shareholders from continuing operations by the weighted average number of common shares outstanding, including all potentially dilutive common shares, if the effect of such common shares is dilutive.

Diluted earnings per common share reflects the dilutive effect of potential common shares from share-based awards and convertible preferred shares. The dilutive effect of the restricted stock, Series B Preferred Stock and Series C Preferred Stock is computed using the if-converted method, which assumes conversion of the restricted stock, Series B Preferred Stock and Series C Preferred Stock at the beginning of the period, giving income recognition for the add-back of the preferred share dividends, amortization of beneficial conversion feature, and undistributed earnings allocated to preferred shareholders. The dilutive effect of restricted stock is computed using the treasury stock method, as applicable, which includes the incremental shares that would be hypothetically vested in excess of the number of shares assumed to be hypothetically repurchased with the assumed proceeds.

Diluted earnings per common share will also reflect the dilutive effect of potential common shares from the conversion of the Convertible Notes. Convertible debt in which the principal amount must be settled in cash is excluded from the calculation of diluted earnings per common share. There would be no interest expense adjustment to the numerator for the cash-settled portion of the Convertible Notes because that portion will always be settled in cash. The conversion spread value in shares will be included in diluted earnings per common share using the if-converted method if the convertible debt is in the money. The denominator of diluted earnings per common share is determined by dividing the conversion spread value of the share-settled portion of the Convertible Notes as of the reporting date by the average share price over the reporting period. For the year ended December 31, 2023, the convertible debt was not in the money; therefore, no incremental shares were assumed converted or included in the diluted earnings per common share calculation. For further details on the Convertible Notes, see Note 13.

The Series C Preferred Stock issued in May 2020 were considered participating securities since these shares participated in dividends on Common Stock on a pari passu, pro rata, as-converted basis. As a result, beginning June 30, 2020, earnings per share on Common Stock was computed using the two-class method required for participating securities during the periods the Series C Preferred Stock was outstanding. As of May 7, 2021, all of the remaining outstanding shares of Series C Preferred Stock were converted into shares of Common Stock and earnings per share on Common Stock and the two-class method was no longer applicable beginning June 30, 2021.
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The following table reconciles numerators and denominators of CenterPoint Energy’s basic and diluted earnings (loss) per common share. Basic earnings per common share calculations:is determined by dividing Income available to common shareholders - basic by the Weighted average common shares outstanding - basic for the applicable period. Diluted earnings per common share is determined by the inclusion of potentially dilutive common stock equivalent shares that may occur if securities to issue Common Stock were exercised or converted into Common Stock.
 For the Year Ended December 31,
 202320222021
 (in millions, except per share and share amounts)
Numerator:
Income from continuing operations$917 $1,057 $668 
Less: Preferred stock dividend requirement (Note 12)50 49 95 
Income available to common shareholders from continuing operations - basic and diluted867 1,008 573 
Income available to common shareholders from discontinued operations - basic and diluted— — 818 
Income available to common shareholders - basic and diluted$867 $1,008 $1,391 
Denominator:
Weighted average common shares outstanding - basic630,947,000 629,415,000 592,933,000 
Plus: Incremental shares from assumed conversions:
Restricted stock2,232,000 2,931,000 5,181,000 
Series C Preferred Stock (1)
— — 11,824,000 
Weighted average common shares outstanding - diluted633,179,000 632,346,000 609,938,000 
Anti-dilutive Incremental Shares Excluded from Denominator for Diluted Earnings Computation:
Series B Preferred Stock (2)
— — 23,906,000 
Earnings per common share:
Basic earnings per common share - continuing operations$1.37 $1.60 $0.97 
Basic earnings per common share - discontinued operations— — 1.38 
Basic Earnings Per Common Share$1.37 $1.60 $2.35 
Diluted earnings per common share - continuing operations$1.37 $1.59 $0.94 
Diluted earnings per common share - discontinued operations— — 1.34 
Diluted Earnings Per Common Share$1.37 $1.59 $2.28 

(1)As of December 31, 2021, all of the outstanding Series C Preferred Stock has been converted into Common Stock. For further information, see Note 12.
(2)As of December 31, 2021, all of the outstanding Series B Preferred Stock has been converted into Common Stock. For further information, see Note 12.

(17) Reportable Segments
 For the Year Ended December 31,
 2017 2016 2015
 (in millions, except per share and share amounts)
Net income (loss) (1)
$1,792
 $432
 $(692)
      
Basic weighted average shares outstanding430,964,000
 430,606,000
 430,180,000
Plus: Incremental shares from assumed conversions: 
  
  
Restricted stock (2)
3,344,000
 2,997,000
 —
Diluted weighted average shares434,308,000
 433,603,000
 430,180,000
      
Basic earnings (loss) per share$4.16
 $1.00
 $(1.61)
      
Diluted earnings (loss) per share$4.13
 $1.00
 $(1.61)


(1)Net income for the year ended December 31, 2017 includes a reduction in income taxes of $1,113 million due to tax reform. See Note 14 for further discussion of the impacts of tax reform implementation.

(2)2,349,000 incremental shares from assumed conversions of restricted stock have not been included in the computation of diluted earnings (loss) per share for the year ended December 31, 2015, as their inclusion would be anti-dilutive.



(17) Unaudited Quarterly Information

Summarized quarterly financial data is as follows:
 Year Ended December 31, 2017
 
First
Quarter
 
Second
Quarter
 
Third
Quarter
 
Fourth
Quarter
 (in millions, except per share amounts)
Revenues$2,735
 $2,143
 $2,098
 $2,638
Operating income274
 223
 279
 296
Net income (1)
192
 135
 169
 1,296
        
Basic earnings per share (2)
$0.45
 $0.31
 $0.39
 $3.01
        
Diluted earnings per share (2)
$0.44
 $0.31
 $0.39
 $2.99
 Year Ended December 31, 2016
 
First
Quarter
 Second
Quarter		 
Third
Quarter
 
Fourth
Quarter
 (in millions, except per share amounts)
Revenues$1,984
 $1,574
 $1,889
 $2,081
Operating income250
 182
 284
 243
Net income (loss)154
 (2) 179
 101
        
Basic earnings (loss) per share (2)
$0.36
 $(0.01) $0.42
 $0.23
        
Diluted earnings (loss) per share (2)
$0.36
 $(0.01) $0.41
 $0.23

(1)Net income for the fourth quarter 2017 includes a reduction in income taxes of $1,113 million due to tax reform. See Note 14 for further discussion of the impacts of tax reform implementation.

(2)Quarterly earnings (loss) per common share are based on the weighted average number of shares outstanding during the quarter, and the sum of the quarters may not equal annual earnings (loss) per common share.

(18) Reportable Business Segments

CenterPoint Energy’sThe Registrants’ determination of reportable business segments considers the strategic operating units under which CenterPoint Energyits CODM manages sales, allocates resources and assesses performance of various products and services to wholesale or retail customers in differing regulatory environments. CenterPoint Energy uses operatingEach Registrant’s CODM views net income as the measure of profit or loss for its businessthe reportable segments.

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As of December 31, 2023, reportable segments other than Midstream Investments, where it uses equity in earnings.by Registrant are as follows:


CenterPoint Energy

•CenterPoint Energy’s Electric reportable business segments include the following: Electric Transmission & Distribution, Natural Gas Distribution, Energy Services, Midstream Investments and Other Operations. Thesegment consisted of electric transmission and distribution function (Houston Electric) is reportedservices in the Electric Transmission & Distribution business segment.Texas gulf coast area in the ERCOT region and electric transmission and distribution services primarily to southwestern Indiana and includes power generation and wholesale power operations in the MISO region.

•CenterPoint Energy’s Natural Gas Distributionreportable segment consists of (i) intrastate natural gas sales to, and natural gas transportation and distribution for residential, commercial, industrial and institutional customers. Energy Services represents customers in Indiana, Louisiana, Minnesota, Mississippi, Ohio and Texas; and (ii) permanent pipeline connections through interconnects with various interstate and intrastate pipeline companies through CEIP.

•CenterPoint Energy’s non-rate regulated gas salesCorporate and services operations. Midstream InvestmentsOther category consists of CenterPoint Energy’s equity investment in Enable. Other Operations consists primarilyenergy performance contracting and sustainable infrastructure services by Energy Systems Group through June 30, 2023, the date of otherthe sale of Energy Systems Group, and corporate support operations whichthat support all of CenterPoint Energy’s business operations. CenterPoint Energy’s Corporate and Other also includes office buildings and other real estate used for business operations.


Long-livedHouston Electric

•Houston Electric’s single reportable segment consisted of electric transmission services to transmission service customers in the ERCOT region and distribution service to REPs in the Texas gulf coast area that includes the city of Houston.

CERC

•CERC’s single reportable segment following the Restructuring consisted of (i) intrastate natural gas sales to, and natural gas transportation and distribution for residential, commercial, industrial and institutional customers in Indiana, Louisiana, Minnesota, Mississippi, Ohio and Texas; and (ii) permanent pipeline connections through interconnects with various interstate and intrastate pipeline companies through CEIP.

Expenditures for long-lived assets include net property, plant and equipment, goodwill and other intangibles and equity investments in unconsolidated subsidiaries.equipment. Intersegment sales are eliminated in consolidation.consolidation, except as described in Note 4.




Financial data for businessreportable segments is as follows, including Discontinued Operations for reconciliation purposes:

CenterPoint Energy
 Revenues
from
External
Customers		Intersegment RevenuesDepreciation
and
Amortization		Interest Income (1)Interest ExpenseIncome Tax Expense
(Benefit)		Net Income (Loss)
(in millions)
For the year ended December 31, 2023:     
Electric$4,290 $— $872 $19 $(303)$189 $654 
Natural Gas4,276 3 513 10 (188)(25)533 
Corporate and Other130 — 16 34 (264)6 (270)
Eliminations— (3)— (54)54 — — 
Consolidated$8,696 $— $1,401 $9 $(701)$170 917 
For the year ended December 31, 2022:     
Electric$4,108 $— $793 $4 $(235)$147 $603 
Natural Gas4,946 — 466 2 (137)243 492 
Corporate and Other267 — 29 59 (214)(30)(38)
Eliminations— — — (62)62 — — 
Consolidated$9,321 $— $1,288 $3 $(524)$360 1,057 
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 Revenues
from
External
Customers		Intersegment RevenuesDepreciation
and
Amortization		Interest Income (1)Interest ExpenseIncome Tax Expense
(Benefit)		Net Income (Loss)
(in millions)
For the year ended December 31, 2021:     
Electric$3,763 $— $775 $— $(226)$95 $475 
Natural Gas4,336 — 527 1 (141)80 403 
Corporate and Other253 — 14 118 (278)(65)(210)
Eliminations— — — (116)116 — — 
Continuing Operations$8,352 $— $1,316 $3 $(529)$110 668 
Discontinued Operations, net818 
Consolidated$1,486 
(1) Interest income from Securitization Bonds of $4 million, less than $1 million, and products$1 million for the years ended December 31, 2023, 2022 and services2021, respectively, is included in Other income, net on both CenterPoint Energy’s and Houston Electric’s respective Statements of Consolidated Income.
Total AssetsExpenditures for Long-lived Assets
December 31,December 31,
 2023 2022202320222021
(in millions)
Electric$21,089 $19,024 $2,660 $2,611 $2,008 
Natural Gas17,429 18,043 1,697 1,697 1,178 
Corporate and Other, net of eliminations (1)
1,197 1,479 13 107 42 
Continuing Operations39,715  38,546 4,370 4,415 3,228 
Divestitures/Discontinued Operations— — — 3 171 
Consolidated$39,715 $38,546 $4,370 $4,418 $3,399 

(1)Total assets included pension and other postemployment-related regulatory assets of $385 million and $405 million as of December 31, 2023 and 2022, respectively.

Divestitures and Discontinued Operations (CenterPoint Energy and CERC)

For further information regarding CenterPoint Energy’s and CERC’s divestitures and discontinued operations, see Note 4.

Houston Electric

Houston Electric consists of a single reportable segment; therefore, a tabular reportable segment presentation has not been
included.

CERC

CERC consists of a single reportable segment; therefore, a tabular reportable segment presentation has not been included.

Major Customers (Houston Electric)

Houston Electric’s revenues from major external customers are as follows:

Year Ended December 31,
202320222021
(in millions)
Affiliates of NRG$1,106 $1,046 $905 
Affiliates of Vistra Energy Corp.539 489 410 

165

 
Revenues
from
External
Customers
  
Intersegment
Revenues
 
Depreciation
and
Amortization
 
Operating
Income
 
Total
Assets (1)
  
Expenditures
for Long-Lived
Assets
 (in millions)
As of and for the year ended December 31, 2017: 
  
       
  
 
Electric Transmission & Distribution$2,997
(2)$—
 $724
 $610
 $10,292
 $924
Natural Gas Distribution2,606
  
33
 260
 328
 6,608
 523
Energy Services3,997
  
52
 19
 125
 1,521
 11
Midstream Investments (3)—
 —
 —
 —
 2,472
 —
Other14
  
—
 33
 9
 2,497
(4)36
Eliminations—
  
(85) —
 —
 (654) —
Consolidated$9,614
  
$—
 $1,036
 $1,072
 $22,736
 1,494
Reconciling items          (68)
Capital expenditures per Statements of Consolidated Cash Flows          $1,426
As of and for the year ended December 31, 2016: 
  
 
  
  
  
  
Electric Transmission & Distribution$3,060
(2)$—
 $838
 $628
 $10,211
 $858
Natural Gas Distribution2,380
  
29
 242
 303
 6,099
 510
Energy Services2,073
  
26
 7
 20
 1,102
 5
Midstream Investments (3)—
 —
 —
 —
 2,505
 —
Other15
  
—
 39
 8
 2,681
(4)33
Eliminations—
  
(55) —
 —
 (769) —
Consolidated$7,528
  
$—
 $1,126
 $959
 $21,829
 1,406
Reconciling items          8
Capital expenditures per Statements of Consolidated Cash Flows          $1,414
As of and for the year ended December 31, 2015: 
  
         
Electric Transmission & Distribution$2,845
(2)$—
 $705
 $607
 $10,028
 $934
Natural Gas Distribution2,603
  
29
 222
 273
 5,657
 601
Energy Services1,924
  
33
 5
 42
 857
 5
Midstream Investments (3)—
 —
 —
 —
 2,594
 —
Other14
  
—
 38
 11
 2,879
(4)35
Eliminations—
  
(62) —
 —
 (725) —
Consolidated$7,386
  
$—
 $970
 $933
 $21,290
  
1,575
Reconciling items          9
Capital expenditures per Statements of Consolidated Cash Flows          $1,584
Revenues by Products and Services

 Year Ended December 31,
202320222021
Revenues by Products and Services:CenterPoint EnergyHouston ElectricCERCCenterPoint EnergyHouston ElectricCERCCenterPoint EnergyHouston ElectricCERC
 (in millions)
Electric delivery$3,701 $3,677 $— $3,438 $3,412 $— $3,158 $3,134 $— 
Retail electric sales569 — — 630 — — 559 — — 
Wholesale electric sales20 — — 40 — — 46 — — 
Retail gas sales4,078 — 3,951 4,759 — 4,613 4,157 — 4,021 
Gas transportation11 — 11 12 — 12 12 — 12 
Energy products and services317 — 187 442 — 175 420 — 167 
Total$8,696 $3,677 $4,149 $9,321 $3,412 $4,800 $8,352 $3,134 $4,200 
(1)Amounts for 2015 have been restated to reflect the adoption of ASU 2015-03.


(2)Houston Electric’s transmission and distribution revenues from major customers are as follows:
(18) Supplemental Disclosure of Cash Flow and Balance Sheet Information

Supplemental Disclosure of Cash Flow Information

CenterPoint Energy elected not to separately disclose discontinued operations on its Statements of Consolidated Cash Flows. The tables below provide supplemental disclosure of cash flow information:
202320222021
CenterPoint EnergyHouston ElectricCERCCenterPoint EnergyHouston ElectricCERCCenterPoint EnergyHouston ElectricCERC
(in millions)
Cash Payments/Receipts:
Interest, net of capitalized interest (under further review)$664 $287 $175 $480 $223 $104 $489 $208 $130 
Income tax payments (refunds), net (1)
215 12 115 421 142 37 (46)20 (7)
Non-cash transactions:
Accounts payable related to capital expenditures246 166 74 335 168 139 370 261 128 
Fair value of Energy Transfer Common Units received for Enable Merger— — — — — — 1,672 — — 
Fair value of Energy Transfer Series G Preferred Units received for Enable Merger— — — — — — 385 — — 
ROU assets obtained in exchange for lease liabilities (2)
3 1 — 7 6 — 2 — — 
(1) CenterPoint Energy’s $215 million income tax payments in 2023 were attributable to recovery of extraordinary gas costs incurred in the February 2021 Winter Storm through the Railroad Commission ordered securitization.
(2) Excludes ROU assets obtained through prepayment of the lease liabilities. See Note 20.

166

  Year Ended December 31, 2017
  2017 2016 2015
  (in millions)
Affiliates of NRG $713
 $698
 $741
Affiliates of Vistra Energy Corp. 229
 220
 220
The table below provides a reconciliation of cash, cash equivalents and restricted cash reported in the Consolidated Balance Sheets to the amount reported in the Statements of Consolidated Cash Flows:

December 31, 2023December 31, 2022
CenterPoint EnergyHouston ElectricCERCCenterPoint EnergyHouston ElectricCERC
(in millions)
Cash and cash equivalents (1)
$90 $76 $1 $74 $75 $— 
Restricted cash included in Prepaid expenses and other current assets
19 13 — 17 13 — 
Total cash, cash equivalents and restricted cash shown in Statements of Consolidated Cash Flows$109 $89 $1 $91 $88 $— 



(1)Cash and cash equivalents related to VIEs as of December 31, 2023 and 2022 included $90 million and $75 million, respectively, at CenterPoint Energy and $76 million and $75 million, respectively, at Houston Electric.
(3)Midstream Investments’ equity earnings (losses) are as follows:

Supplemental Disclosure of Balance Sheet Information

Included in other current liabilities on CERC’s Consolidated Balance Sheets as of December 31, 2023 and 2022 was $118 million and $61 million, respectively, of credits related to customers on budget billing programs. Included in other current liabilities on Houston Electric’s Consolidated Balance Sheets as of December 31, 2023 and 2022 was $47 million and $35 million, respectively, of accrued contributions in aid of construction.

(19) Related Party Transactions (Houston Electric and CERC)

Houston Electric and CERC participate in a money pool through which they 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 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 table below summarizes money pool activity:
December 31, 2023December 31, 2022
Houston ElectricCERCHouston ElectricCERC
 (in millions, except interest rates)
Money pool investments (borrowings) (1)
$238 $1 $(642)$— 
Weighted average interest rate5.59 %5.59 %4.75 %4.75 %

(1)Included in Accounts and notes receivable (payable)–affiliated companies in Houston Electric’s and CERC’s Consolidated Balance Sheets, as applicable.

Houston Electric and CERC affiliate-related net interest income (expense) were as follows:
Year Ended December 31,
202320222021
Houston ElectricCERCHouston ElectricCERCHouston Electric
CERC (1)
(in millions)
Interest income (expense), net (2)
$2 $10 $— $(18)$— $(38)

(1)Includes affiliate-related net interest expense of Indiana Gas and VEDO to reflect the Restructuring.
(2)Interest income is included in Other, net and interest expense is included in Interest expense and other finance charges on Houston Electric’s and CERC’s respective Statements of Consolidated Income.

CenterPoint Energy provides some corporate services to Houston Electric and CERC. The costs of services have been charged directly to Houston Electric and CERC using methods that management believes are reasonable. These methods include negotiated usage rates, dedicated asset assignment and proportionate corporate formulas based on operating expenses, assets, gross margin, employees and a composite of assets, gross margin and employees. Houston Electric provides certain
167

  Year Ended December 31, 2017
  2017 2016 2015 (a)
  (in millions)
Enable $265
 $208
 $(1,633)
services to CERC. These services are billed at actual cost, either directly or as an allocation and include fleet services, shop services, geographic services, surveying and right-of-way services, radio communications, data circuit management and field operations. Additionally, CERC provides certain services to Houston Electric. These services are billed at actual cost, either directly or as an allocation and include line locating and other miscellaneous services. These charges are not necessarily indicative of what would have been incurred had Houston Electric and CERC not been affiliates.


(a)Includes impairment charges totaling $1,846 million composed of CenterPoint Energy’s impairment of its equity method investment in Enable of $1,225 million and CenterPoint Energy’s share, $621 million, of impairment charges Enable recorded for goodwill and long-lived assets for the year ended December 31, 2015. This impairment is offset by $213 million of earnings for the year ended December 31, 2015.

Amounts charged for these services are included primarily in Operation and maintenance expenses:
(4)
Included in total assets of Other Operations as of December 31, 2017, 2016 and 2015, are pension and other postemployment related regulatory assets of $600 million, $759 million and $814 million, respectively.
Year Ended December 31,
202320222021
Houston ElectricCERCHouston ElectricCERCHouston ElectricCERC
(in millions)
Corporate service charges$173 $236 $167 $237 $189 $257 
Net affiliate service charges (billings)(10)10 15 (15)(7)7 
The table below presents transactions among Houston Electric, CERC and their parent, Utility Holding.
Year Ended December 31,
202320222021
Houston ElectricCERCHouston ElectricCERCHouston ElectricCERC
(in millions)
Cash dividends paid to parent$367 $496 $316 $124 $— $— 
Cash dividend paid to parent related to the sale of the Arkansas and Oklahoma Natural Gas businesses— — — 720 — — 
Cash contribution from parent885 500 1,143 289 130 140 
Net assets acquired in the Restructuring (1)
— — — 2,345 — — 
Non-cash capital contribution from parent in payment for property, plant and equipment below— — 38 54 — — 
Cash paid to parent for property, plant and equipment below— — 65 61 — — 
Property, plant and equipment from parent (2)
— — 103 115 — — 

(1)The Restructuring was a common control transaction that required the recasting of financial information to the earliest period presented. Therefore, the net asset transfer is not reflected during the year ended December 31, 2022 on CERC’s Statements of Consolidated Changes in Equity.
(2)Property, plant and equipment purchased from CenterPoint Energy at its net carrying value on the date of purchase.

(20) Leases

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

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

The Registrants’ lease agreements do not contain any material residual value guarantees, material restrictions or material covenants. There are no lease transactions with related parties. Agreements in which the Registrants are lessors do not include
168

  Year Ended December 31,
Revenues by Products and Services: 2017 2016 2015
  (in millions)
Electric delivery $2,997
 $3,060
 $2,845
Retail gas sales 3,634
 3,329
 3,725
Wholesale gas sales 2,811
 977
 657
Gas transportation and processing 29
 23
 26
Energy products and services 143
 139
 133
Total $9,614
 $7,528
 $7,386
provisions for the lessee to purchase the assets. Because risk is minimal, the Registrants do not take any significant actions to manage risk associated with the residual value of their leased assets.


The Registrants’ operating lease agreements are primarily equipment and real property leases, including land and office facility leases. CenterPoint Energy and Houston Electric also have finance lease agreements for mobile generators. The Registrants’ lease terms may include options to extend or terminate a lease when it is reasonably certain that those options will be exercised. The Registrants have elected an accounting policy that exempts leases with terms of one year or less from the recognition requirements of ASC 842.
(19)
In 2021, Houston Electric entered into a temporary short-term lease and long-term leases for mobile generation. The short-term lease agreement allows Houston Electric to take delivery of TEEEF assets on a short-term basis with an initial term ending on September 30, 2022 and extended until December 31, 2022. At such time, the short-term lease agreement expired and all mobile generation assets were leased under the long-term lease agreement. Per Houston Electric’s short-term lease accounting policy election, a ROU asset and lease liability were not reflected on Houston Electric’s Consolidated Balance Sheets. Expenses associated with the short-term lease, including carrying costs, are deferred to a regulatory asset and totaled $100 million and $103 million as of December 31, 2023 and 2022, respectively.

The long-term lease agreement includes up to 505 MW of TEEEF, all of which was delivered as of December 31, 2022, triggering lease commencement at delivery, with an initial term ending in 2029 for all TEEEF leases. The total cash payments under the long-term lease totaled $664 million, with the final $485 million paid in 2022. These assets were previously available under the short-term lease agreement. Houston Electric derecognized the finance lease liability when the extinguishment criteria in Topic 405 - Liabilities was achieved. Per the terms of the agreement, lease payments are due and made in full by Houston Electric upon taking possession of the asset, relieving substantially all of the associated finance lease liability at that time. The remaining finance lease liability associated with the commenced long-term TEEEF agreement was not significant as of December 31, 2023 and 2022 and relates to removal costs that will be incurred at the end of the lease term. As of December 31, 2023, Houston Electric has secured a first lien on the assets leased under the prepayment agreement, except for assets with lease payments totaling $97 million. The $97 million prepayment is being held in an escrow account, not controlled by Houston Electric, and the funds will be released when a first lien can be secured by Houston Electric. Expenses associated with the long-term lease, including depreciation expense on the right of use asset and carrying costs, are deferred to a regulatory asset and totaled $124 million and $60 million as of December 31, 2023 and 2022, respectively. The long-term lease agreement contains a termination clause that can be exercised in the event of material adverse regulatory actions. If the right to terminate is elected, subject to the satisfaction of certain conditions, 75% of Houston Electric’s prepaid lease costs that is attributable to the period from the effective date of termination to the end of the lease term would be refunded. In December 2022, the long-term lease agreement was amended to include a disallowance reimbursement clause that can be exercised in the event that any regulatory proceeding or settlement agreement results in a disallowance of Houston Electric’s recovery of deferred costs under either the long-term lease agreement, short-term lease agreement or any other quantifiable adverse financial impact to Houston Electric. The disallowance reimbursement clause expired on December 31, 2023 and Houston Electric can no longer seek relief in the event of an unfavorable regulatory ruling. For further discussion of the regulatory impacts, see Note 7.

Houston Electric will also incur variable costs throughout the lease term for the operation and maintenance of the generators. Lease costs, including variable and ROU asset amortization costs, are deferred to Regulatory assets as incurred as a recoverable cost under the 2021 Texas legislation. See Note 7 for further information regarding recovery of these deferred costs.

The components of lease cost, included in Operation and maintenance expense on the Registrants’ respective Statements of Consolidated Income, are as follows:

Year Ended December 31,
202320222021
CenterPoint EnergyHouston
Electric		CERCCenterPoint EnergyHouston
Electric		CERCCenterPoint EnergyHouston
Electric		CERC
(in millions)
Operating lease cost$6 $3 $2 $6 $1 $2 $8 $1 $4 
Short-term lease cost31 30 $— 167 166 1 119 118 — 
Total lease cost (1)
$37 $33 $2 $173 $167 $3 $127 $119 $4 

(1) CenterPoint Energy and Houston Electric defer finance lease costs for TEEEF to Regulatory assets for recovery rather than to Depreciation and Amortization in the Statements of Consolidated Income.
169


The components of lease income were as follows:

Year Ended December 31,
2023 2022 2021
CenterPoint EnergyHouston
Electric		CERCCenterPoint EnergyHouston
Electric		CERCCenterPoint EnergyHouston
Electric		CERC
(in millions)
Operating lease income$6 $1 $4 $5 $1 $3 $6 $1 $3 
Variable lease income2 — — 2 — — 1 — — 
Total lease income$8 $1 $4 $7 $1 $3 $7 $1 $3 

Supplemental balance sheet information related to leases was as follows:
December 31, 2023December 31, 2022
CenterPoint EnergyHouston
Electric		CERCCenterPoint EnergyHouston
Electric		CERC
(in millions, except lease term and discount rate)
Assets:
Operating ROU assets (1)
$13 $6 $4 $19 $6 $5 
Finance ROU assets (2)
526 $526 — 621 621 — 
Total leased assets$539 $532 $4 $640 $627 $5 
Liabilities:
Current operating lease liability (3)
$3 $1 $1 $5 $1 $2 
Non-current operating lease liability (4)
10 $5 3 14 5 4 
Total leased liabilities (5)
$13 $6 $4 $19 $6 $6 
Weighted-average remaining lease term (in years) - operating leases4.73.93.14.34.83.9
Weighted-average discount rate - operating leases4.13 %4.09 %3.60 %3.80 %4.01 %3.58 %
Weighted-average remaining lease term (in years) - finance leases5.55.5— 6.56.5— 
Weighted-average discount rate - finance leases3.60 %3.60 %— 3.60 %3.60 %— 

(1)Reported within Other assets in the Registrants’ respective Consolidated Balance Sheets, net of accumulated amortization.
(2)Reported within Property, Plant and Equipment in the Registrants’ respective Consolidated Balance Sheets, net of accumulated amortization.
(3)Reported within Current other liabilities in the Registrants’ respective Consolidated Balance Sheets.
(4)Reported within Other liabilities in the Registrants’ respective Consolidated Balance Sheets.
(5)Finance lease liabilities were not material as of December 31, 2023 or 2022 and are reported within Other long-term debt in the Registrants’ respective Consolidated Balance Sheets when applicable.

170

As of December 31, 2023, finance lease liabilities were not significant to the Registrants. As of December 31, 2023, maturities of operating lease liabilities were as follows:
CenterPoint
 Energy		Houston
 Electric		CERC
(in millions)
2024$4 $2 $2 
20253 2 1 
20263 1 1 
20272 1 — 
20281 — — 
2029 and beyond2 — — 
Total lease payments15 6 4 
Less: Interest2 — — 
Present value of lease liabilities$13 $6 $4 

As of December 31, 2023, future minimum finance lease payments to be received were not significant to the Registrants. As of December 31, 2023, maturities of undiscounted operating lease payments to be received are as follows:
CenterPoint
 Energy		Houston
 Electric		CERC
(in millions)
2024$6 $1 $4 
20258 1 5 
20268 — 5 
20277 — 5 
20287 — 5 
2029 and beyond173 — 170 
Total lease payments to be received$209 $2 $194 

Other information related to leases is as follows:

Year Ended December 31,
202320222021
CenterPoint EnergyHouston
Electric		CERCCenterPoint EnergyHouston
Electric		CERCCenterPoint EnergyHouston
Electric		CERC
(in millions)
Operating cash flows from operating leases included in the measurement of lease liabilities$5 $2 $2 $6 $1 $2 $6 $1 $3 
Financing cash flows from finance leases included in the measurement of lease liabilities— — — 485 485 — 179 179 — 

See Note 18 for information on ROU assets obtained in exchange for operating lease liabilities.

(21) Subsequent Events


January 2024 Equity Distribution Agreement (CenterPoint Energy)

On January 10, 2024, CenterPoint Energy entered into an Equity Distribution Agreement with certain financial institutions with respect to the offering and sale from time to time of shares of Common Stock, having an aggregate gross sales price of up to $500 million. Sales of Common Stock may be made by any method permitted by applicable law and deemed to be an “at the market offering” as defined in Rule 415 of the Securities Act of 1933. CenterPoint Energy may also enter into one or more forward sales agreements pursuant to master forward confirmations. The offer and sale of Common Stock under the Equity Distribution Agreement will terminate upon the earliest of (1) the sale of all Common Stock subject to the Equity Distribution
171

Agreement, (2) termination of the Equity Distribution Agreement, or (3) May 17, 2026.As of February 20, 2024, CenterPoint Energy has not issued any shares of Common Stock under the Equity Distribution Agreement and has not entered into any forward sale agreements.

Proposed Divestiture of Louisiana and Mississippi Natural Gas Local Distribution Companies (CenterPoint Energy and CERC)

On February 9, 2018, Enable declared a quarterly cash19, 2024, CERC Corp. entered into the LAMS Asset Purchase Agreement, pursuant to which CERC Corp. has agreed to sell its Louisiana and Mississippi regulated natural gas local distribution of $0.318 per unit on all of its outstanding common unitscompany businesses. The purchase price for the quarter ended December 31, 2017. Accordingly, CERC Corp. expectsLouisiana and Mississippi regulated natural gas local distribution company businesses is $1.2 billion and subject to receiveadjustment as set forth in the LAMS Asset Purchase Agreement, including adjustments based on net working capital, regulatory assets and liabilities and capital expenditures at closing. The completion of the proposed transaction is subject to customary closing conditions, including (i) the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, (ii) approval of the LPSC, (iii) approval of the MPSC, (iv) no Material Adverse Effect (as defined in the LAMS Asset Purchase Agreement) having occurred, and (v) customary closing conditions regarding the accuracy of the representations and warranties and compliance by the parties with the respective obligations under the LAMS Asset Purchase Agreement. The proposed transaction is not subject to a cash distributionfinancing condition and is expected to close by the end of approximately $74 million from Enable in the first quarter of 20182025, subject to be madesatisfaction of the foregoing conditions.

Item 9.Changes in and Disagreements with respect to CERC Corp.’s limited partner interest in Enable for the fourth quarter of 2017.Accountants on Accounting andFinancial Disclosure

On February 9, 2018, Enable declared a quarterly cash distribution of $0.625 per Series A Preferred Unit for the quarter ended December 31, 2017. Accordingly, CenterPoint Energy expects to receive a cash distribution of approximately $9 million from Enable in the first quarter of 2018 to be made with respect to CenterPoint Energy’s investment in Series A Preferred Units of Enable for the fourth quarter of 2017.

Item 9.
Changes in and Disagreements with Accountants on Accounting andFinancial Disclosure


None.


Item 9A.Controls and Procedures

Item 9A.Controls and Procedures

Disclosure Controls And Procedures


In accordance with Exchange Act Rules 13a-15 and 15d-15, wethe Registrants carried out an evaluation,separate evaluations, under the supervision and with the participation of each company’s management, including ourthe principal executive officer and principal financial officer, of the effectiveness of ourthe disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, ourthose evaluations, the principal executive officer and principal financial officer, in each case, concluded that ourthe disclosure controls and procedures were effective as of December 31, 20172023 to provide assurance that information required to be disclosed in ourthe reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’sSEC’s rules and forms and such information is accumulated and communicated to our management, including ourthe principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding disclosure.


There has been no change in ourthe Registrants’ internal controls over financial reporting that occurred during the three months ended December 31, 20172023 that has materially affected, or is reasonably likely to materially affect, ourthe Registrants’ internal controls over financial reporting.





172


Management’s Annual Report on Internal Control over Financial Reporting


OurThe Registrants’ management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is defined in Rule 13a-15(f) or 15d-15(f) promulgated under the Securities Exchange Act of 1934 as a process designed by, or under the supervision of, the company’sRegistrants’ principal executive and principal financial officers and effected by the company’sCenterPoint Energy’s board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles and includes those policies and procedures that:


•Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the company;Registrants;


•Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the companyRegistrants are being made only in accordance with authorizations of management and directors of the company;Registrants; and


•Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’sRegistrants’ assets that could have a material effect on the financial statements.


Management has designed its internal control over financial reporting to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with accounting principles generally accepted in the United States of America. Management’s assessment included review and testing of both the design effectiveness and operating effectiveness of controls over all relevant assertions related to all significant accounts and disclosures in the financial statements.


All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.


Under the supervision and with the participation of ourthe Registrants’ management, including ourtheir respective principal executive officerofficers and principal financial officer, weofficers, the Registrants conducted an evaluation of the effectiveness of ourtheir internal control over financial reporting based on the framework in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on ourthe Registrants’ evaluation under the framework in Internal Control — Integrated Framework (2013), ourthe Registrants’ management has concluded, in each case, that ourtheir internal control over financial reporting was effective as of December 31, 2017.2023.


Deloitte & Touche LLP, the Company’sCenterPoint Energy’s independent registered public accounting firm, has issued an attestation report on the effectiveness of ourCenterPoint Energy’s internal control over financial reporting as of December 31, 20172023 which is set forth below. This report is not applicable to Houston Electric or CERC as they are not accelerated or large accelerated filers.



173












REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and Board of Directors and Shareholders of
CenterPoint Energy, Inc.
Houston, Texas
Opinion on Internal Control over Financial Reporting

We have audited the internal control over financial reporting of CenterPoint Energy, Inc. and subsidiaries (the “Company”) as of December 31, 2017,2023, based on criteria established in Internal Control -— Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017,2023, based on criteria established in Internal Control -— Integrated Framework (2013) issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2017,2023, of the Company and our report dated February 22, 2018,20, 2024, expressed an unqualified opinion on those financial statements.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.


/s/ DELOITTE & TOUCHE LLP

Houston, Texas
February 22, 201820, 2024

174




Item 9B.Other Information

Item 9B.Other Information

Amendments to Articles of Incorporation or Bylaws; Change in Fiscal Year (CenterPoint Energy)

On February 16, 2024, CenterPoint Energy filed the following statements of resolutions with the Secretary of State of the State of Texas for the purpose of deleting the Series A Preferred Stock, the Series B Preferred Stock and the Series C Preferred Stock from CenterPoint Energy’s Restated Articles of Incorporation:

•Statement of Resolutions Deleting Series of Shares designated Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Stock of CenterPoint Energy, Inc. (the Series A Statement of Resolutions);

•Statement of Resolutions Deleting Series of Shares designated 7.00% Series B Mandatory Convertible Preferred Stock of CenterPoint Energy, Inc. (the Series B Statement of Resolutions); and

•Statement of Resolutions Deleting Series of Shares designated Series C Mandatory Convertible Preferred Stock of CenterPoint Energy, Inc. (the Series C Statement of Resolutions and, collectively with the Series A Statement of Resolutions and the Series B Statement of Resolutions, the Statements of Resolutions).

None of the previously issued shares of Series A Preferred Stock, Series B Preferred Stock or Series C Preferred Stock remained outstanding prior to filing the Statements of Resolutions.

Effective upon filing, the Statements of Resolutions deleted all references to the Series A Preferred Stock, the Series B Preferred Stock and the Series C Preferred Stock contained in CenterPoint Energy’s Restated Articles of Incorporation. The shares that were designated to such series were returned to the status of authorized but unissued shares of preferred stock, par value $0.01 per share, of CenterPoint Energy, without designation as to series.

Copies of the Series A Statement of Resolutions, the Series B Statement of Resolutions and the Series C Statement of Resolutions are filed as Exhibits 3(m), 3(n) and 3(o), respectively, and are incorporated herein by reference.

Effective February 16, 2024, the Board amended and restated CenterPoint Energy’s bylaws (the Bylaws). The Bylaws include, among other things, the following changes:

•revise procedures and disclosure for the nomination of directors and the submission of proposals for consideration at meetings of the shareholders of CenterPoint Energy, including, among other things, (x) consolidating the advance notice provisions applicable to all proposals (i.e., director nominations, proposals to amend CenterPoint Energy’s bylaws, proposals to remove directors and all other proposals (other than “proxy access” nominations and shareholder proposals made pursuant to Section 14a-8 of the Securities and Exchange Act of 1934, as amended (the “Exchange Act”)) into a single section and (y) adding a requirement that a shareholder seeking to nominate director(s) at an annual meeting deliver to CenterPoint Energy reasonable evidence that it has complied with the requirements of Rule 14a-19 of the Exchange Act within eight business days of the meeting;

•clarify that for the applicability of the majority voting standard for uncontested elections of directors, an election remains “contested” (and the plurality voting standard applies) even if the Board determines that a shareholder’s nomination notice does not comply with the advance notice bylaws;

•adopt a forum selection bylaw to provide that the U.S. federal district courts shall be the exclusive forum for the resolution of claims under the Securities Act of 1933, as amended; and

•make certain administrative, modernizing, clarifying and conforming changes, including (x) making updates to reflect amendments to the Texas Business Organizations Code, as amended, (y) expressly providing that meetings of shareholders may be held in whole or in part by means of remote communications in accordance with applicable law and (z) adopting gender-neutral terms when referring to particular positions, offices or title holders, including the adoption of the title Chair in place of Chairman.

The foregoing description of the terms of the Bylaws does not purport to be complete and is subject to, and qualified in its entirety by, reference to the complete text of the Bylaws. The Bylaws, along with a copy marked to show changes from the prior version, are included as Exhibits 3(h) and 3(i), respectively, to this Annual Report on Form 10-K and incorporated by reference herein.

175

Compensatory Arrangements of Certain Officers (CenterPoint Energy)

Amendments to Forms of Award Agreements under Long-Term Incentive Plan


On February 21, 2018,15, 2024, the Compensation Committee of the Board of Directors of CenterPoint Energy approved new forms of award agreementsagreement under CenterPoint Energy’s LTIP for performance share awards and restricted stock unit awards and performance unit awards.


Among other things, theThe newly approved forms of award agreementsagreement for officers and director employees providerevise and simplify the retirement provisions by adopting a single retirement provision that a “retirement eligible” (age 55provides the opportunity for full vesting if the award was granted prior to the calendar year of the participant’s retirement or greater with at least five years of service) participant, who meetspro-rata vesting if the requirements for enhanced retirement as specified under the agreement will fully vestaward was granted in the award,calendar year of the participants retirement, in all cases subject in the case of performance share awards, to the achievement of the relevant performance metrics. The requirementsTo be eligible for enhancedsuch retirement include havingvesting, the participant must (i) be at least 55 years old with a sum of age and years of employment equal toservice of 65 or greater, providing(ii) provide at least sixthree months’ written notice (or reasonable advance written notice for officers subject to Section 16 of the Exchange Act) of retirement, providingand (iii) provide a comprehensive transition plan and retiring on or after the January 1 immediately following the grant (for restricted stock units) or the first anniversary of the beginning of the designated performance cycle (for performance share awards).plan. In addition, for officers subject to Section 16 of the Exchange Act, eligibility for enhanced retirement vesting is subject to approval by the Compensation Committee.

In connection with a change in control of CenterPoint Energy (as defined in the LTIP), the newly approved forms of award agreements provide for full vesting if (a) such awards are not assumed or continued, or substituted with a substantially equivalent award, by the surviving or successor entity, or (b) the award holder is terminated (other than due to death, disability, voluntary resignation or for cause) within two years after the date upon which such change in control occurred.


In addition, the newly approved forms of award agreements provide for vesting upon death or termination due to disability. The newly approved forms of award agreements also include restrictive covenants (confidentiality,agreement revised the non-solicitation and non-competition provisions) that provide for forfeiture of unpaid awards and return of paid awards upon violation.confidentiality provisions to reflect changes in the law.


The description of the forms of award agreements, as amended, isagreement are qualified in itstheir entirety by reference to the full text of the forms of performance sharerespective form award and restricted stock unit award agreements,agreement, which are included as Exhibits 10(q)(2)10(cc)(13), 10(q)(3)10(cc)(14), 10(q)(5) and 10(q)(7) hereto and incorporated by reference herein.10(cc)(15).


With respect toOn February 15, 2024, the newlyCompensation Committee also approved form of award agreement3-year ratable vesting for annual restricted stock unit awards (retention) only, such agreement has been updated solely for purposesunder which one third (1/3) of the change in controlunderlying units vest and restrictive covenant provisions described above. The descriptionare payable as of the formfirst three anniversaries of award agreement for restricted stockthe grant date, subject to the participant’s continued employment and achievement of the applicable performance goal. The Compensation Committee also approved a price-to-earnings (P/E) modifier to performance share unit awards (retention), as amended, is qualifiedunder the Company’s LTIP based on total shareholder return. Under the P/E modifier, if CenterPoint Energy’s P/E ratio ranks in its entirety by reference to the full texttop quartile of CenterPoint Energy’s peer group, a P/E modifier will apply that provides for a minimum 75% payout level for the award regardless of the formlevel of restricted stock unit award agreement (retention), whichtotal shareholder return performance achieved. This vesting schedule and the P/E modifier does not apply to previously granted awards.

Rule 10b5-1 Trading Arrangements

During the three months ended December 31, 2023, no director or officer of CenterPoint Energy, Houston Electric or CERC adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is included as Exhibit 10(q)(6) hereto and incorporated by reference herein.defined in Item 408 of Regulation S-K.


Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections

Not Applicable.

PART III


Item 10.Directors, Executive Officers and Corporate Governance

TheItem 10.Directors, Executive Officers and Corporate Governance

For CenterPoint Energy, the information called for by Item 10, to the extent not set forth in “Executive“Information About Our Executive Officers” in Item 1 of Part I of this report, will be set forth in the definitive proxy statement relating to CenterPoint Energy’s 20182024 annual meeting of shareholders pursuant to SEC Regulation 14A. Such definitive proxy statement relates to a meeting of shareholders involving the election of directors and the portions thereof called for by Item 10 are incorporated herein by reference pursuant to Instruction G to Form 10-K.


Item 11.Executive Compensation

For Houston Electric and CERC, the information called for by Item 10 is omitted pursuant to Instruction I(2) to Form 10-K (Omission of Information by Certain Wholly-Owned Subsidiaries).
The
Item 11.Executive Compensation

For CenterPoint Energy, the information called for by Item 11 will be set forth in the definitive proxy statement relating to CenterPoint Energy’s 20182024 annual meeting of shareholders pursuant to SEC Regulation 14A. Such definitive proxy statement relates to a meeting of shareholders involving the election of directors and the portions thereof called for by Item 11 are incorporated herein by reference pursuant to Instruction G to Form 10-K.

176



Item 12.
Security Ownership of Certain Beneficial Owners and Managementand Related Stockholder Matters


TheFor Houston Electric and CERC, the information called for by Item 11 is omitted pursuant to Instruction I(2) to Form 10-K (Omission of Information by Certain Wholly-Owned Subsidiaries).

Item 12.Security Ownership of Certain Beneficial Owners and Managementand Related Stockholder Matters

For CenterPoint Energy, the information called for by Item 12 will be set forth in the definitive proxy statement relating to CenterPoint Energy’s 20182024 annual meeting of shareholders pursuant to SEC Regulation 14A. Such definitive proxy statement relates to a meeting of shareholders involving the election of directors and the portions thereof called for by Item 12 are incorporated herein by reference pursuant to Instruction G to Form 10-K.


Item 13.
Certain Relationships and Related Transactions, and DirectorIndependence

For Houston Electric and CERC, the information called for by Item 12 is omitted pursuant to Instruction I(2) to Form 10-K (Omission of Information by Certain Wholly-Owned Subsidiaries).
The
Item 13.Certain Relationships and Related Transactions, and DirectorIndependence

For CenterPoint Energy, the information called for by Item 13 will be set forth in the definitive proxy statement relating to CenterPoint Energy’s 20182024 annual meeting of shareholders pursuant to SEC Regulation 14A. Such definitive proxy statement relates to a meeting of shareholders involving the election of directors and the portions thereof called for by Item 13 are incorporated herein by reference pursuant to Instruction G to Form 10-K.


Item 14.Principal Accounting Fees and Services

For Houston Electric and CERC, the information called for by Item 13 is omitted pursuant to Instruction I(2) to Form 10-K (Omission of Information by Certain Wholly-Owned Subsidiaries).
The
Item 14.Principal Accounting Fees and Services

For CenterPoint Energy, the information called for by Item 14 will be set forth in the definitive proxy statement relating to CenterPoint Energy’s 20182024 annual meeting of shareholders pursuant to SEC Regulation 14A. Such definitive proxy statement relates to a meeting of shareholders involving the election of directors and the portions thereof called for by Item 14 are incorporated herein by reference pursuant to Instruction G to Form 10-K.


Aggregate fees billed to Houston Electric and CERC during the years ended December 31, 2023 and 2022 by their principal accounting firm, Deloitte & Touche LLP, are set forth below.
 Year Ended December 31,
 20232022
Houston ElectricCERCHouston ElectricCERC
Audit fees (1)
$843,661 $1,155,700 $708,180 $965,700 
Audit-related fees (2)
530,000 410,000 435,000 559,000 
Total audit and audit-related fees1,373,661 1,565,700 1,143,180 1,524,700 
Tax fees— — — — 
All other fees— — — — 
Total fees$1,373,661 $1,565,700 $1,143,180 $1,524,700 
(1)For 2023 and 2022, amounts include fees for services provided by the principal accounting firm relating to the integrated audit of financial statements and internal control over financial reporting, statutory audits, attest services, and regulatory filings.
(2)For 2023 and 2022, amounts include fees for consultations concerning financial accounting and reporting standards and various agreed-upon or expanded procedures related to accounting records to comply with financial accounting or regulatory reporting matters.

Houston Electric and CERC each are not required to have, and do not have, an audit committee.


177

PART IV


Item 15.Exhibits and Financial Statement Schedules

Item 15.Exhibits and Financial Statement Schedules

(a)(1) Financial Statements.

CenterPoint Energy
Report of Independent Registered Public Accounting Firm (PCAOB ID No. 34)
7284
Statements of Consolidated Income for the Three Years Ended December 31, 20172023
7386
Statements of Consolidated Comprehensive Income for the Three Years Ended December 31, 20172023
7487
Consolidated Balance Sheets as of December 31, 20172023 and 20162022
7588
Statements of Consolidated Cash Flows for the Three Years Ended December 31, 20172023
7790
Statements of Consolidated Shareholders’Changes in Equity for the Three Years Ended December 31, 20172023
7991
Houston Electric
Report of Independent Registered Public Accounting Firm (PCAOB ID No. 34)
92
Statements of Consolidated Income for the Three Years Ended December 31, 2023
94
Statements of Consolidated Comprehensive Income for the Three Years Ended December 31, 2022
1
Consolidated Balance Sheets as of December 31, 2023 and 2022
95
Statements of Consolidated Cash Flows for the Three Years Ended December 31, 2023
97
Statements of Consolidated Changes in Equity for the Three Years Ended December 31, 2023
97
CERC
Report of Independent Registered Public Accounting Firm (PCAOB ID No. 34)
99
Statements of Consolidated Income for the Three Years Ended December 31, 2023
101
Statements of Consolidated Comprehensive Income for the Three Years Ended December 31, 2023
102
Consolidated Balance Sheets as of December 31, 2023 and 2022
103
Statements of Consolidated Cash Flows for the Three Years Ended December 31, 2023
105
Statements of Consolidated Changes in Equity for the Three Years Ended December 31, 2023
106
Combined Notes to Consolidated Financial Statements
80107


The financial statements of Enable Midstream Partners, LP required pursuant to Rule 3-09 of Regulation S-X are included in this filing for CenterPoint Energy as Exhibit 99.1.


(a)(2) Financial Statement Schedules for the Three Years Ended December 31, 2017.2023


The following schedules are omitted by the Registrants because of the absence of the conditions under which they are required or because the required information is included in the financial statements:


I, II, III, IV and V.


(a)(3) Exhibits.


See Index of Exhibits beginning on page 130,179, which index also includes the management contracts or compensatory plans or arrangements required to be filed as exhibits to this Form 10-K by Item 601(b)(10)(iii) of Regulation S-K.


Item 16.Form 10-K Summary

None.




178

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC AND SUBSIDIARIES
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

EXHIBITS TO THE COMBINED ANNUAL REPORT ON FORM 10-K
For Fiscal Year Ended December 31, 20172023


INDEX OF EXHIBITS


Exhibits included with this report are designated by a cross (†); all exhibits not so designated are incorporated herein by reference to a prior filing as indicated. Exhibits designated by an asterisk (*) are management contracts or compensatory plans or arrangements required to be filed as exhibits to this Form 10-K by Item 601(b)(10)(iii) of Regulation S-K. CenterPoint Energy hasThe Registrants have not filed the exhibits and schedules to Exhibit 2. CenterPoint EnergyThe Registrants hereby agreesagree to furnish supplementally a copy of any schedule omitted from Exhibit 2 to the SEC upon request.


The agreements included as exhibits are included only to provide information to investors regarding their terms.  The agreements listed below may contain representations, warranties and other provisions that were made, among other things, to provide the parties thereto with specified rights and obligations and to allocate risk among them, and such agreements should not be relied upon as constituting or providing any factual disclosures about us, any other persons, any state of affairs or other matters.
Exhibit
Number
 Description Report or Registration Statement 
SEC File or
Registration
Number
 
Exhibit
Reference
2—
Transaction Agreement dated July 21, 2004 among CenterPoint Energy, Utility Holding, LLC, NN Houston Sub, Inc., Texas Genco Holdings, Inc. (Texas Genco), HPC Merger Sub, Inc. and GC Power Acquisition LLC
 CenterPoint Energy’s Form 8-K dated July 21, 2004 1-31447 10.1
3(a)—
Restated Articles of Incorporation of CenterPoint Energy
 CenterPoint Energy’s Form 8-K dated July 24, 2008 1-31447 3.2
3(b)—
Third Amended and Restated Bylaws of CenterPoint Energy
 
CenterPoint Energy’s Form 8-K dated February 21, 2017

 1-31447 3.1
3(c)—
Statement of Resolutions Deleting Shares Designated Series A Preferred Stock of CenterPoint Energy

 CenterPoint Energy’s Form 10-K for the year ended December 31, 2011 1-31447 3(c)
4(a)—
Form of CenterPoint Energy Stock Certificate
 CenterPoint Energy’s Registration Statement on Form S-4 333-69502 4.1
4(b)—
Contribution and Registration Agreement dated December 18, 2001 among Reliant Energy, CenterPoint Energy and the Northern Trust Company, trustee under the Reliant Energy, Incorporated Master Retirement Trust
 CenterPoint Energy’s Form 10-K for the year ended December 31, 2001 1-31447 4.3
4(c)(1)—Mortgage and Deed of Trust, dated November 1, 1944 between Houston Lighting and Power Company (HL&P) and Chase Bank of Texas, National Association (formerly, South Texas Commercial National Bank of Houston), as Trustee, as amended and supplemented by 20 Supplemental Indentures thereto HL&P’s Form S-7 filed on August 25, 1977 2-59748 2(b)
4(c)(2)—Twenty-First through Fiftieth Supplemental Indentures to Exhibit 4(c)(1) HL&P’s Form 10-K for the year ended December 31, 1989 1-3187 4(a)(2)
4(c)(3)—Fifty-First Supplemental Indenture to Exhibit 4(c)(1) dated as of March 25, 1991 HL&P’s Form 10-Q for the quarter ended June 30, 1991 1-3187 4(a)
4(c)(4)—Fifty-Second through Fifty-Fifth Supplemental Indentures to Exhibit 4(c)(1) each dated as of March 1, 1992 HL&P’s Form 10-Q for the quarter ended March 31, 1992 1-3187 4
4(c)(5)—Fifty-Sixth and Fifty-Seventh Supplemental Indentures to Exhibit 4(c)(1) each dated as of October 1, 1992  HL&P’s Form 10-Q for the quarter ended September 30, 1992 1-3187 4


Exhibit
Number		DescriptionReport or Registration StatementSEC File or
Registration
Number		Exhibit
Reference		CenterPoint EnergyHouston ElectricCERC
2(a)—CenterPoint Energy’s Form 8-K dated July 21, 20041-3144710.1X
2(b)—

CenterPoint Energy’s Form 8-K dated April 21, 2018
1-314472.1X
2(c)(1)—Agreement and Plan of Merger among CERC, Houston Lighting and Power Company (“HL&P”), HI Merger, Inc. and NorAm Energy Corp. (“NorAm”) dated August 11, 1996Houston Industries’ (“HI’s”) Form 8-K dated August 11, 19961-76292X
2(c)(2)—Amendment to Agreement and Plan of Merger among CERC, HL&P, HI Merger, Inc. and NorAm dated August 11, 1996Registration Statement on Form S-4333-113292(c)X
2(d)—Agreement and Plan of Merger dated December 29, 2000 merging Reliant Resources Merger Sub, Inc. with and into Reliant Energy Services, Inc.Registration Statement on Form S-3333-545262X
2(e)—CenterPoint Energy’s Form 8-K dated March 14, 2013
1-314472.1XX
179

Exhibit
Number		DescriptionReport or Registration StatementSEC File or
Registration
Number		Exhibit
Reference		CenterPoint EnergyHouston ElectricCERC
2(f)—
Securities Purchase Agreement, dated as of February 3, 2020, by and among Vectren Utility Services, Inc., PowerTeam Services, LLC and, solely for purposes of Section 10.17 of the Securities Purchase Agreement, Vectren Corporation

CenterPoint Energy’s Form 8-K dated February 3, 2020
1-314472.1X
2(g)—CenterPoint Energy’s Form 8-K dated February 24, 2020
1-314472.1XX
2(h)—CenterPoint Energy’s Form 10-Q for the quarter ended March 31, 20211-314472.4XX
3(a)—CenterPoint Energy’s Form 8-K dated July 24, 20081-314473.2X
3(b)—Houston Electric’s Form 8-K dated August 31, 20021-31873(a)X
3(c)—

Houston Electric’s Form 10-Q for the quarter ended June 30, 2011
1-3187
3.1X
3(d)—

CERC Form 10-K for the year ended December 31, 1997
1-13265
3(a)(1)X
3(e)—

CERC Form 10-K for the year ended December 31, 1997
1-13265
3(a)(2)X
3(f)—

CERC Form 10-K for the year ended December 31, 1998
1-13265
3(a)(3)X
3(g)—

CERC Form 10-Q for the quarter ended June 30, 2003
1-13265
3(a)(4)X
†3(h)—


X
†3(i)—X
3(j)—

Houston Electric’s Form 10-Q for the quarter ended June 30, 2011
1-3187
3.2X
3(k)—CERC Form 10-K for the year ended December 31, 1997
1-132653(b)X
180

Exhibit
Number		DescriptionReport or Registration StatementSEC File or
Registration
Number		Exhibit
Reference		CenterPoint EnergyHouston ElectricCERC
3(l)—

CenterPoint Energy’s Form 10-K for the year ended December 31, 20111-314473(c)X
†3(m)—X
†3(n)—X
†3(o)—X
4(a)—CenterPoint Energy’s Registration Statement on Form S-4333-695024.1X
4(b)—CenterPoint Energy’s Form 10-K for the year ended December 31, 20011-314474.3X
4(c)(1)—Mortgage and Deed of Trust, dated November 1, 1944 between Houston Lighting and Power Company (HL&P) and Chase Bank of Texas, National Association (formerly, South Texas Commercial National Bank of Houston), as Trustee, as amended and supplemented by 20 Supplemental Indentures theretoHL&P’s Form S-7 filed on August 25, 19772-597482(b)XX
4(c)(2)—Twenty-First through Fiftieth Supplemental Indentures to Exhibit 4(c)(1)HL&P’s Form 10-K for the year ended December 31, 19891-31874(a)(2)XX
4(c)(3)—Fifty-First Supplemental Indenture to Exhibit 4(c)(1) dated as of March 25, 1991HL&P’s Form 10-Q for the quarter ended June 30, 19911-31874(a)XX
4(c)(4)—Fifty-Second through Fifty-Fifth Supplemental Indentures to Exhibit 4(c)(1) each dated as of March 1, 1992HL&P’s Form 10-Q for the quarter ended March 31, 19921-31874XX
181

Exhibit
Number		DescriptionReport or Registration StatementSEC File or
Registration
Number		Exhibit
Reference		CenterPoint EnergyHouston ElectricCERC
4(c)(5)—Fifty-Sixth and Fifty-Seventh Supplemental Indentures to Exhibit 4(c)(1) each dated as of October 1, 1992 HL&P’s Form 10-Q for the quarter ended September 30, 19921-31874XX
4(c)(6)—Fifty-Eighth and Fifty-Ninth Supplemental Indentures to Exhibit 4(c)(1) each dated as of March 1, 1993HL&P’s Form 10-Q for the quarter ended March 31, 19931-31871-31874X4X
4(c)(7)—Sixtieth Supplemental Indenture to Exhibit 4(c)(1) dated as of July 1, 1993HL&P’s Form 10-Q for the quarter ended June 30, 19931-31871-31874X4X
4(c)(8)—Sixty-First through Sixty-Third Supplemental Indentures to Exhibit 4(c)(1) each dated as of December 1, 1993HL&P’s Form 10-K for the year ended December 31, 19931-31871-31874(a)(8)X4(a)(8)X
4(c)(9)—Sixty-Fourth and Sixty-Fifth Supplemental Indentures to Exhibit 4(c)(1) each dated as of July 1, 1995HL&P’s Form 10-K for the year ended December 31, 19951-31871-31874(a)(9)X4(a)(9)X
4(d)(1)—Houston Electric’s Form 10-Q for the quarter ended September 30, 20021-31871-31874(j)(1)X4(j)(1)X
4(d)(2)—Houston Electric’s Form 10- Q for the quarter ended September 30, 20021-31874(j)(3)
4(d)(3)—
Third Supplemental Indenture to Exhibit 4(d)(1), dated as of October 10, 2002
Houston Electric’s Form 10-Q for the quarter ended September 30, 20021-31871-31874(j)(4)X4(j)(4)X
4(d)(4)(3)—CenterPoint Energy’s Form 10-K for the year ended December 31, 20031-314471-314474(e)(10)X4(e)(10)X
4(d)(5)(4)—CenterPoint Energy’s Form 10-K for the year ended December 31, 20021-314471-314474(e)(10)X4(e)(10)X
4(d)(6)(5)—CenterPoint Energy’s Form 8-K dated March 13, 20031-314471-314474.1X4.1X
4(d)(7)(6)—CenterPoint Energy’s Form 8-K dated March 13, 20031-314471-314474.2X4.2X
4(d)(8)(7)—CenterPoint Energy’s Form 8-K dated May 16, 20031-314474.2
4(d)(9)—
Officer’s Certificate dated May 23, 2003 setting forth the form, terms and provisions of the Twelfth Series of General Mortgage Bonds
CenterPoint Energy’s Form 8-K dated May 16, 20031-314474.1
4(d)(10)—
Twentieth Supplemental Indenture to Exhibit 4(d)4(d)(1), dated as of December 9, 2008
Houston Electric’s Form 8-K dated January 6, 20091-31871-31874.2X4.2X
182

Exhibit
Number		DescriptionReport or Registration StatementSEC File or
Registration
Number		Exhibit
Reference		CenterPoint EnergyHouston ElectricCERC
4(d)(11)(8)—CenterPoint Energy’s Form 10-K for the year ended December 31, 20121-314471-314474(e)(33)X4(e)(33)X
4(d)(12)(9)—CenterPoint Energy’s Form 10-K for the year ended December 31, 20121-314471-314474(e)(34)X4(e)(34)X
4(d)(13)(10)—CenterPoint Energy’s Form 10-Q for the quarter ended March 31, 20141-314471-314474.10X4.10X
4(d)(14)(11)—CenterPoint Energy’s Form 10-Q for the quarter ended March 31, 20141-314471-314474.11X4.11X
4(d)(15)(12)—CenterPoint Energy’s Form 10-Q for the quarter ended June 30, 20161-314474.5


4(d)(16)—
Officer’s Certificate, dated as of May 18, 2016, setting forth the form, terms and provisions of the Twenty-Fifth Series of General Mortgage Bonds
CenterPoint Energy’s Form 10-Q for the quarter ended June 30, 20161-314474.6
4(d)(17)—
Twenty-Fifth Supplemental Indenture to Exhibit 4(d)(1) dated as of August 11, 2016 to the General Mortgage Indenture, dated as of October 10, 2002, between Houston Electric and the Trustee
CenterPoint Energy’s Form 10-Q for the quarter ended September 30, 20161-314471-314474.5X4.5X
4(d)(18)(13)—CenterPoint Energy’s Form 10-Q for the quarter ended September 30, 20161-314471-314474.6X4.6X
4(d)(19)(14)—CenterPoint Energy’s Form 10-K for the year ended December 31, 20161-314471-314474(e)(41)X4(e)(41)X
4(d)(20)(15)—CenterPoint Energy’s Form 10-K for the year ended December 31, 20161-314474(e)(42)XX
4(d)(16)

—

CenterPoint Energy’s Form 10-Q for the quarter ended March 30, 20181-314474.9XX
4(d)(17)

—CenterPoint Energy’s Form 10-Q for the quarter ended March 30, 20181-314474.10XX
4(d)(18)—Houston Electric’s Form 8-K dated January 10, 20191-31874.4XX
4(d)(19)—CenterPoint Energy’s Form 10-K for the year ended December 31, 20181-314474(h)(24)XX
183

Exhibit
Number		DescriptionReport or Registration StatementSEC File or
Registration
Number		Exhibit
Reference		CenterPoint EnergyHouston ElectricCERC
4(d)(20)—



Houston Electric’s Form 8-K dated June 2, 20201-31874.4XX
4(d)(21)—CenterPoint Energy’s Form 10-Q for the quarter ended June 30, 20201-314474.26XX
4(d)(22)—Houston Electric’s Form 8-K dated March 8, 20211-31874.4XX
4(d)(23)—CenterPoint Energy’s Form 10-Q for the quarter ended March 31, 20211-314474.22XX
4(d)(24)—Houston Electric’s Form 8-K dated February 23, 20221-31874.4X
4(d)(25)—CenterPoint Energy’s Form 10-Q for the quarter ended March 31, 20221-314474.11X
4(d)(26)—Houston Electric’s Form 8-K dated September 12, 20221-31874.4X
4(d)(27)—CenterPoint Energy’s Form 10-Q for the quarter ended September 30, 20221-314474.7X
4(d)(28)—Houston Electric’s Form 8-K dated March 20, 20231-31874.4X
4(d)(29)—CenterPoint Energy’s Form 10-Q for the quarter ended March 31, 20231-314474.11X
4(d)(30)—Houston Electric’s Form 8-K dated September 13, 20231-31874.4X
4(d)(31)—CenterPoint Energy’s Form 10-Q for the quarter ended September 30, 20231-314474.9X
184

Exhibit
Number		DescriptionReport or Registration StatementSEC File or
Registration
Number		Exhibit
Reference		CenterPoint EnergyHouston ElectricCERC
4(e)(1)—Indenture, dated as of February 1, 1998, between Reliant Energy Resources Corp. (RERC Corp.) and Chase Bank of Texas, National Association, as TrusteeCERC Corp.’s Form 8-K dated February 5, 19981-132651-132654.1X4.1X
4(e)(2)—CenterPoint Energy’s Form 10-K for the year ended December 31, 20061-314471-314474(f)(11)X4(f)(11)X
4(e)(3)—CenterPoint Energy’s Form 10-Q for the quarter ended June 30, 20081-314471-314474.9X4.9X
4(e)(4)—CenterPoint Energy’s Form 10-K for the year ended December 31, 20101-314471-314474(f)(15)X4(f)(15)X
4(e)(5)—CenterPoint Energy’s Form 10-K for the year ended December 31, 20101-314474(f)(16)
4(e)(6)—
Supplemental Indenture No. 16 to Exhibit 4(e)4(e)(1) dated as of August 23, 2017, providing for the issuance of CERC Corp.’s 4.10% Senior Notes due 2047
CenterPoint Energy’s Form 10-Q for the quarter ended September 30, 20171-314474.11XX
4(e)(6)—

CERC’s Form 10-Q for the quarter ended March 31, 2018
1-13265
4.4XX
4(e)(7)—CenterPoint Energy’s Form 10-Q for the quarter ended September 30, 20201-314474.23XX
4(e)(8)—CenterPoint Energy’s Form 10-Q for the quarter ended June 30, 20221-314474.12X
4(e)(9)—CERC’s Form 8-K dated October 5, 20221-132654.2X
4(e)(10)—CenterPoint Energy’s Form 10-Q for the quarter ended March 31, 20231-314474.64.11X
185

Exhibit
Number		DescriptionReport or Registration StatementSEC File or
Registration
Number		Exhibit
Reference		CenterPoint EnergyHouston ElectricCERC
4(e)(11)—CenterPoint Energy’s Form 10-Q for the quarter ended June 30, 20231-314474.5X
4(f)(1)—CenterPoint Energy’s Form 8-K dated May 19, 20031-314471-314474.1X4.1
4(f)(2)—

CenterPoint Energy’s Form 10-Q for the quarter ended September 30, 2018
1-31447
4.14X
4(f)(3)—

CenterPoint Energy’s Form 10-Q for the quarter ended September 30, 2019
1-31447
4.2X
4(f)(4)—CenterPoint Energy’s Form 10-Q for the quarter ended June 30, 20211-314474.24X
4(f)(5)—CenterPoint Energy’s Form 10-Q for the quarter ended June 30, 20211-314474.25X
4(f)(6)—CenterPoint Energy’s Form 10-Q for the quarter ended September 30, 201720231-314474.44.9X
4(g)(1)—Subordinated Indenture dated as of September 1, 1999Reliant Energy’s Form 8-K dated September 1, 19991-31871-31874.1X4.1
4(g)(2)—Supplemental Indenture No. 1 dated as of September 1, 1999, between Reliant Energy and Chase Bank of Texas (supplementing Exhibit 4(g)(1) and providing for the issuance Reliant Energy’s 2% Zero-Premium Exchangeable Subordinated Notes Due 2029)Reliant Energy’s Form 8-K dated September 15, 19991-31871-31874.2X4.2


186

Exhibit
Number		DescriptionReport or Registration StatementSEC File or
Registration
Number		Exhibit
Reference		CenterPoint EnergyHouston ElectricCERC
4(g)(3)—CenterPoint Energy’s Form 8-K12B dated August 31, 20021-314471-314474(e)X4(e)
4(g)(4)—CenterPoint Energy’s Form 10-K for the year ended December 31, 20051-314474(h)(4)X
4(h)(1)—

CenterPoint Energy’s Form 8-K dated January 30, 20231-3144710.2X
4(h)(2)—CenterPoint Energy’s Form 8-K dated March 15, 20231-314474.2X
4(h)(3)—CenterPoint Energy’s Form 8-K dated October 13, 20231-314474.2X
4(h)(4)—Additional Supplemental Indentures to Exhibit 4(h)(1)X
Date as ofFile ReferenceExhibit No.
 July 1, 1999
1-3553, SIGECO’s Form 10-Q for the quarter ended June 30, 19994(a)
April 1, 2013
1-15467, Vectren’s Form 8-K dated April 30, 20134.1
September 1, 2014
1-15467, Vectren’s Form 8-K dated September 25, 20144.1
September 1, 2015
1-15467, Vectren’s Form 8-K dated September 10, 20154.1
4(i)(1)—Indenture dated February 1, 1991 between Indiana Gas Company, Inc. and U.S Bank Trust National Association (formerly known as First Trust National Association, which was formerly known as Bank of America Illinois, which was formerly known as Continental Bank, National Association)Indiana Gas’s Form 8-K filed February 15, 19911-64944(a)X
187

Exhibit
Number		DescriptionReport or Registration StatementSEC File or
Registration
Number		Exhibit
Reference		CenterPoint EnergyHouston ElectricCERC
4(i)(2)—First Supplemental Indenture to Exhibit 4(i)(1), dated as of February 15, 1991Indiana Gas’s Form 8-K filed February 15, 19911-64944(b)X
4(i)(3)—Second Supplemental Indenture to Exhibit 4(i)(1), dated as of September 15, 1991Indiana Gas’s Form 8-K filed September 25, 19911-64944(b)X
4(i)(4)—Third Supplemental Indenture to Exhibit 4(i)(1), dated as of September 15, 1991Indiana Gas’s Form 8-K filed September 25, 19911-64944(c)X
4(i)(5)—Fourth Supplemental Indenture to Exhibit 4(i)(1), dated as of December 2, 1992Indiana Gas’s Form 8-K filed December 8, 19921-64944(b)X
4(i)(6)—Indiana Gas’s Form 8-K filed December 27, 20001-64944X
4(j)(1)—Vectren’s Form 8-K dated September 25, 20171-154674.1X
4(j)(2)—Vectren’s Form 8-K dated May 3, 20181-154674.1X
4(j)(3)—Vectren’s Form 8-K dated May 3, 20181-154674.2X
4(j)(4)—CenterPoint Energy’s Form 10-K for the year ended December 31, 200520221-314474(k)(4)4(h)(4)X
4(h)(1)4(k)—CenterPoint Energy’s Form 8-K dated May 27, 20221-314474.1XX
4(l)—CenterPoint Energy’s Form 8-K dated May 27, 20221-314474.3XX
188

Exhibit
Number		DescriptionReport or Registration StatementSEC File or
Registration
Number		Exhibit
Reference		CenterPoint EnergyHouston ElectricCERC
4(m)—CenterPoint Energy’s Form 8-K dated May 27, 20221-314474.4XX
4(n)—CenterPoint Energy’s Form 8-K dated May 27, 20221-314474.5XX
4(o)—CERC’s Form 8-K dated October 5, 20221-132654.3X
4(p)—CenterPoint Energy’s Form 8-K dated March 3, 2016August 4, 20231-314474.14.1X
4(h)(2)†4(q)—

CenterPoint Energy’s Form 8-K dated June 16, 2017

Securities
X1-314474.1
4(i)(1)†4(r)—XCenterPoint Energy’s Form 8-K dated March 3, 20161-314474.2
4(i)(2)†4(s)—CenterPoint Energy’s Form 8-K dated June 16, 20171-314474.2
4(j)(1)—
$600,000,000 Credit Agreement dated as of March 3, 2016, among CERC Corp., as Borrower, and the banks named therein
CenterPoint Energy’s Form 8-K dated March 3, 20161-314474.3
4(j)(2)—
First Amendment to Credit Agreement, dated as of June 16, 2017, among CERC Corp., as Borrower, and the banks named therein
CenterPoint Energy’s Form 8-K dated June 16, 20171-314474.3X

Pursuant to Item 601(b)(4)(iii)(A) of Regulation S-K, CenterPoint Energy hasthe Registrants have not filed as exhibits to this Form 10-K certain long-term debt instruments, including indentures, under which the total amount of securities authorized does not exceed 10% of the total assets of CenterPoint Energythe Registrants and its subsidiaries on a consolidated basis. CenterPoint EnergyThe Registrants hereby agreesagree to furnish a copy of any such instrument to the SEC upon request.
 
Exhibit
Number		Description
Exhibit
Number
DescriptionReport or Registration Statement
SEC File or

Registration

Number
Exhibit
Reference
Exhibit
Reference
CenterPoint EnergyHouston ElectricCERC
*10(a)—CenterPoint Energy’s Form 10-Q for the quarter ended March 31, 20111-314471-3144710.3X10.3
*10(b)(1)—CenterPoint Energy’s Form 8-K dated December 22, 20081-314471-3144710.1X10.1
189

Exhibit
Number		DescriptionReport or Registration StatementSEC File or
Registration
Number		Exhibit
Reference		CenterPoint EnergyHouston ElectricCERC
*10(b)(2)—CenterPoint Energy’s Quarterly Report on Form 10-Q for the quarter ended March 31, 20111-3144710.4X
*10(b)(3)—CenterPoint Energy’s Quarterly Report on Form 10-Q for the quarter ended March 31, 20221-3144710.14X
*10(b)(4)—CenterPoint Energy’s Quarterly Report on Form 10-Q for the quarter ended September 30, 20231-3144710.210.4X
*10(c)—CenterPoint Energy’s Form 10-Q for the quarter ended September 30, 20031-314471-3144710.1X10.1
*10(d)(1)—CenterPoint Energy’s Form 8-K dated December 22, 20081-314471-3144710.4X10.4
*10(d)(2)—CenterPoint Energy’s Quarterly Report on Form 10-Q for the quarter ended March 31, 20111-314471-3144710.5X10.5
*10(e)(1)—CenterPoint Energy’s Form 8-K dated December 22, 20081-314471-3144710.3X10.3


*10(e)(2)—CenterPoint Energy’s Quarterly Report on Form 10-Q for the quarter ended March 31, 20111-314471-3144710.6X10.6
*10(e)(3)—CenterPoint Energy’s Form 8-K dated December 9, 20191-3144710.1X
*10(e)(4)—CenterPoint Energy’s Quarterly Report on Form 10-Q for the quarter ended March 31, 20221-3144710.18X
190

Exhibit
Number		DescriptionReport or Registration StatementSEC File or
Registration
Number		Exhibit
Reference		CenterPoint EnergyHouston ElectricCERC
*10(f)10(e)(5)—CenterPoint Energy’s Quarterly Report on Form 10-Q for the quarter ended September 30, 20231-3144710.3X
†*10(e)(6)—X
†*10(e)(7)X
*10(f)—CenterPoint Energy’s Form 10-Q for the quarter ended September 30, 20031-314471-3144710.5X10.5
10(g)(1)—Stockholder’s Agreement dated as of July 6, 1995 between Houston Industries Incorporated and Time Warner Inc. Schedule 13-D dated July 6, 19955-193515-193512X2
10(g)(2)—Amendment to Exhibit 10(g)(1) dated November 18, 1996HI’s Form 10-K for the year ended December 31, 19961-76291-762910(x)(4)X10(x)(4)
†10(h)(1)—
10(i)(1)—
Master Separation Agreement entered into as of December 31, 2000 between Reliant Energy, Incorporated and Reliant Resources, Inc.
Reliant Energy’s Form 10-Q for the quarter ended March 31, 20011-31871-318710.1X10.1
10(i)10(h)(2)—CenterPoint Energy’s Form 10-K for the year ended December 31, 20021-314471-3144710(bb)(5)X10(bb)(5)
10(i)10(h)(3)—Reliant Energy’s Form 10-Q for the quarter ended March 31, 20011-31871-318710.5X10.5
10(i)10(h)(4)—Reliant Energy’s Form 10-Q for the quarter ended March 31, 20011-31871-318710.6X10.6
10(i)10(h)(5)—Reliant Energy’s Form 10-Q for the quarter ended March 31, 20011-31871-318710.8X10.8
10(j)10(i)(1)—CenterPoint Energy’s Form 10-K for the year ended December 31, 20021-314471-3144710(cc)(1)X10(cc)(1)
191

Exhibit
Number		DescriptionReport or Registration StatementSEC File or
Registration
Number		Exhibit
Reference		CenterPoint EnergyHouston ElectricCERC
10(j)10(i)(2)—CenterPoint Energy’s Form 10-K for the year ended December 31, 20021-314471-3144710(cc)(2)X10(cc)(2)
10(j)10(i)(3)—CenterPoint Energy’s Form 10-K for the year ended December 31, 20021-314471-3144710(cc)(3)X10(cc)(3)
*10(k)10(j)(1)—CenterPoint Energy’s Form 10-Q for the quarter ended June 30, 20031-314471-3144710.2X10.2
*10(k)10(j)(2)—CenterPoint Energy’s Form 8-K dated February 20, 20081-314471-3144710.4X10.4
*10(l)10(k)(1)—CenterPoint Energy’s Form 8-K dated February 20, 20081-3144710.3
*10(l)(2)—
Amended and Restated CenterPoint Energy 2005 Deferred Compensation Plan, effective January 1, 2009
CenterPoint Energy’s Form 10-Q for the quarter ended September 30, 20081-3144710.1X
*10(k)(2)—CenterPoint Energy’s Form 8-K dated April 22, 20221-3144710.10X
*10(k)(3)—CenterPoint Energy’s Form 10-Q for the quarter ended March 31, 20221-3144710.11X
*10(k)(4)—CenterPoint Energy’s Form 10-Q for the quarter ended September 30, 200820231-3144710.110.1X
†*10(m)(1)10(k)(5)—X
*10(l)(1)—

CenterPoint Energy Form 10-K for the year ended December 31, 20211-3144710(l)X
*10(l)(2)—CenterPoint Energy Form 10-K for the year ended December 31, 20221-3144710(l)(2)X
*10(m)(1)—

CenterPoint Energy’s Form 10-Q for the quarter ended September 30, 2003March 31, 2018
1-314471-3144710.1X10.3
192

Exhibit
Number		DescriptionReport or Registration StatementSEC File or
Registration
Number		Exhibit
Reference		CenterPoint EnergyHouston ElectricCERC
*10(m)(3)(2)—CenterPoint Energy’s Form 8-K dated December 10, 20091-3144710.1
*10(n)(1)—
CenterPoint Energy Stock Plan for Outside Directors, as amended and restated effective May 7, 2003
CenterPoint Energy’s Form 10-K for the year ended December 31, 200320191-314471-3144710(n)(2)X10(ll)
*10(n)(2)—CenterPoint Energy’s Form 10-Q for the quarter ended March 31, 20101-3144710.2
*10(n)(3)—
Second Amendment to Exhibit 10(n)(1)
CenterPoint Energy’s Registration Statement on Form S-8333-1736604.6


*10(n)(4)—
Third Amendment to Exhibit 10(n)(1)
CenterPoint Energy’s Form 10-K for the year ended December 31, 20141-3144710(dd)(4)
10(o)—
City of Houston Franchise Ordinance
CenterPoint Energy’s Form 10-Q for the quarter ended June 30, 20051-314471-3144710.1X10.1X
10(p)10(o)(1)—CenterPoint Energy’s Form 10-Q for the quarter ended September 30, 20081-314471-3144710.2X10.2
10(p)10(o)(2)—CenterPoint Energy’s Form 10-Q for the quarter ended September 30, 20081-314471-3144710.3X10.3
*10(q)10(p)(1)—CenterPoint Energy’s Schedule 14A dated March 13, 20091-314471-31447AXA
†*10(q)10(p)(2)—
†*10(q)(3)—
Form of Performance Award Agreement for Executive Chairman 20XX - 20XX Performance Cycle under Exhibit 10(q)(1)
*10(q)(4)—
Form of Restricted Stock Unit Award Agreement (With Performance Goal) under Exhibit 10(q)(1)
CenterPoint Energy’s Form 8-K dated February 28, 201210-K for the year ended December 31, 20191-314471-3144710(q)(2)X10.2
†*10(q)(5)10(p)(3)—CenterPoint Energy’s Form 10-K for the year ended December 31, 20191-3144710(q)(5)X
†*10(q)(6)10(p)(4)—CenterPoint Energy’s Form 8-K dated June 30, 20201-3144710.4X
†*10(q)(7)10(p)(5)—CenterPoint Energy’s Form 8-K dated June 30, 20201-3144710.2X
*10(p)(6)—CenterPoint Energy’s Form 8-K dated June 30, 20201-3144710.3X
*10(p)(7)—CenterPoint Energy’s Form 8-K/A dated June 30, 20201-3144710.1X
*10(p)(8)—CenterPoint Energy’s Form 8-K/A dated June 30, 20201-3144710.2X
*10(p)(9)—CenterPoint Energy’s Form 10-K for the year ended December 31, 20201-3144710(q)(12)X
193

Exhibit
Number		DescriptionReport or Registration StatementSEC File or
Registration
Number		Exhibit
Reference		CenterPoint EnergyHouston ElectricCERC
†10(r)*10(p)(10)—CenterPoint Energy’s Form 10-K for the year ended December 31, 20201-3144710(q)(13)X
†10(s)*10(p)(11)—CenterPoint Energy’s Form 8-K/A dated February 19, 20201-3144710.1X
*10(p)(12)—CenterPoint Energy’s Form 8-K dated July 20, 20211-3144710.1X
10(t)*10(q)(1)—CenterPoint Energy’s Form 8-K dated April 27, 20171-314471-3144710.1X10.1
10(u)*10(q)(2)—CenterPoint Energy’s Form 10-K for the year ended December 31, 20201-3144710(t)(2)X
*10(q)(3)—CenterPoint Energy’s Form 10-K for the year ended December 31, 20211-3144710(q)(3)X
*10(r)—CenterPoint Energy’s Form 10-K for the year ended December 31, 20131-314471-3144710(zz)X10(zz)
*10(s)(1)—Vectren’s Form 10-K for the year end December 31, 20011-1546710.32X
†*10(s)(2)—X
*10(t)—Vectren’s Form 8-K dated September 29, 20081-1546710.3X
*10(u)(1)—Vectren’s Form 8-K dated December 17, 20081-1546710.2X
†*10(u)(2)—X
*10(v)—Vectren’s Form 8-K dated December 17, 20081-1546710.1X
194

Exhibit
Number		DescriptionReport or Registration StatementSEC File or
Registration
Number		Exhibit
Reference		CenterPoint EnergyHouston ElectricCERC
10(v)*10(w)—Vectren’s Form 10-Q for the quarter ended September 30, 20131-1546710.1X
10(x)—CenterPoint Energy’s Form 8-K dated June 30, 20201-3144710.1X
10(y)—CenterPoint Energy’s Form 8-K dated September 15, 20201-3144710.1X
10(z)—CenterPoint Energy’s Form 8-K dated February 16, 20211-3144710.2X
10(aa)—CenterPoint Energy’s Form 10-Q for the quarter ended June 30, 20211-3144710.8X
10(bb)—CenterPoint Energy’s Form 10-Q for the quarter ended June 30, 20211-3144710.9X
*10(cc)(1)—CenterPoint Energy’s Definitive Proxy Statement filed on March 11, 20221-31447Appendix AX
*10(cc)(2)—CenterPoint Energy’s 8-K dated April 22, 20221-3144710.2X
*10(cc)(3)—CenterPoint Energy’s 8-K dated April 22, 20221-3144710.3X
*10(cc)(4)—CenterPoint Energy’s 8-K dated April 22, 20221-3144710.4X
*10(cc)(5)—CenterPoint Energy’s 8-K dated April 22, 20221-3144710.5X
*10(cc)(6)—CenterPoint Energy’s 8-K dated April 22, 20221-3144710.7X
*10(cc)(7)—CenterPoint Energy’s 8-K dated April 22, 20221-3144710.8X
195

Exhibit
Number		DescriptionReport or Registration StatementSEC File or
Registration
Number		Exhibit
Reference		CenterPoint EnergyHouston ElectricCERC
*10(cc)(8)—CenterPoint Energy’s 10-K for the year ended December 31, 20221-3144710(ee)(9)X
*10(cc)(9)—CenterPoint Energy’s 10-K for the year ended December 31, 20221-3144710(ee)(10)X
*10(cc)(10)—CenterPoint Energy’s Form 8-K dated March 14, 201315, 20231-3144710.22.1X
10(w)*10(cc)(11)—CenterPoint Energy’s Form 8-K dated November 14, 2017September 27, 20231-3144710.110.1X
10(x)*10(cc)(12)—CenterPoint Energy’s Form 8-K dated June 22, 2016September 27, 20231-3144710.210.2X
10(y)†*10(cc)(13)X
†*10(cc)(14)X
†*10(cc)(15)X
10(dd)(1)—CenterPoint Energy’s 8-K dated December 6, 20221-3144710.1X
10(dd)(2)—CenterPoint Energy’s Form 10-Q for the quarter ended June 30, 20231-3144710.1X
10(ee)—CenterPoint Energy’s 8-K dated December 6, 20221-3144710.2X
196

Exhibit
Number		DescriptionReport or Registration StatementSEC File or
Registration
Number		Exhibit
Reference		CenterPoint EnergyHouston ElectricCERC
10(ff)—CenterPoint Energy’s 8-K dated December 6, 20221-3144710.3X
10(gg)—CenterPoint Energy’s 8-K dated December 6, 20221-3144710.4X
10(hh)—CenterPoint Energy’s 10-K for the year-ended December 31, 20221-3144710(kk)X
10(ii)—CenterPoint Energy’s Form 8-K/A dated January 3, 20231-3144710.1X
10(jj)—CenterPoint Energy’s Form 8-K dated May 1, 2013March 15, 20231-3144710.110.3X
10(z)10(kk)—CenterPoint Energy’s Form 8-K dated May 1, 2013March 15, 20231-3144710.110.4X
10(aa)10(ll)—CenterPoint Energy’s Form 8-K dated January 28, 2016October 13, 20231-3144710.110.1X
10(bb)†21.1—CenterPoint Energy’s Form 8-K dated February 18, 20161-3144710.2
†12—
Computation of Ratio of Earnings to Fixed Charges
†21—
Subsidiaries of CenterPoint Energy
X
†21.2—


X
†23.1.1
†23.1—X
†23.223.1.2—X
†23.1.3—X
†31.131.1.1—X
†31.231.1.2—X
197

Exhibit
Number		DescriptionReport or Registration StatementSEC File or
Registration
Number		Exhibit
Reference		CenterPoint EnergyHouston ElectricCERC
†32.131.1.3—X
†31.2.1—X
†31.2.2X
†31.2.3X
†32.1.1—X
†32.232.1.2—X
†32.1.3—X
†32.2.1—X
†32.2.2—X
†32.2.3—X
†97.1—X


†97.2—X
†97.3—X
99.1—Part II,I, Item 81 of Enable Midstream Partners, LP’s Form 10-K10-Q for the yearquarter ended December 31, 2017September 30, 2021001-36413001-36413Item 1XItem 8
†101.INS—Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL documentXXX
†101.SCH—Inline XBRL Taxonomy Extension Schema DocumentXXX
†101.CAL—Inline XBRL Taxonomy Extension Calculation Linkbase DocumentXXX
†101.DEF—Inline XBRL Taxonomy Extension Definition Linkbase DocumentXXX
†101.LAB—Inline XBRL Taxonomy Extension Labels Linkbase DocumentXXX
198

Exhibit
Number		DescriptionReport or Registration StatementSEC File or
Registration
Number		Exhibit
Reference		CenterPoint EnergyHouston ElectricCERC
†101.PRE—Inline XBRL Taxonomy Extension Presentation Linkbase DocumentXXX
†104—
Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

XXX




199

SIGNATURES


Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant hasRegistrants have duly caused this report to be signed on itstheir behalf by the undersigned, thereunto duly authorized, in the City of Houston, the State of Texas, on the 22nd20th day of February, 2018.2024.


CENTERPOINT ENERGY, INC.
(Registrant)
By:  /s/ Scott M. ProchazkaJASON P. WELLS
Scott M. ProchazkaJason P. Wells
President and Chief Executive Officer


Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on February 22, 2018.20, 2024.


Signature
SignatureTitle
/s/  SCOTT M. PROCHAZKAJASON P. WELLSPresident, Chief Executive Officer and
Scott M. ProchazkaJason P. WellsDirector (Principal Executive Officer and Director)
/s/  WILLIAM D. ROGERSCHRISTOPHER A. FOSTERExecutive Vice President and Chief Financial Officer
William D. RogersChristopher A. FosterFinancial Officer (Principal(Principal Financial Officer)
/s/  KRISTIE L. COLVINSenior Vice President and Chief Accounting Officer
Kristie L. ColvinAccounting(Duly Authorized Officer (Principaland Principal Accounting Officer)
/s/  WENDOLYNN MONTOYA CLOONANDirector
Wendolynn Montoya Cloonan
/s/  EARL M. CUMMINGSDirector
Earl M. Cummings
/s/ CHRISTOPHER H. FRANKLINDirector
Christopher H. Franklin
/s/  RAQUELLE W. LEWISDirector
Raquelle W. Lewis
/s/  MILTON CARROLLTHADDEUS J. MALIKExecutive Chairman of the Board of DirectorsDirector
Milton CarrollThaddeus J. Malik
/s/  MICHAEL P. JOHNSONDirector
Michael P. Johnson
/s/  JANIECE M. LONGORIADirector
Janiece M. Longoria
/s/  SCOTT J. MCLEANDirector
Scott J. McLean
/s/  THEODORE F. POUNDDirector
Theodore F. Pound
/s/  SUSAN O. RHENEYRICKY A. RAVENDirector
Susan O. RheneyRicky A. Raven
/s/  PHILLIP R. SMITHDirector
Phillip R. Smith
/s/  BARRY T. SMITHERMANDirector
Barry T. Smitherman

200


CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC
(Registrant)
By:/s/ LYNNAE K. WILSON
Lynnae K. Wilson
President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on February 20, 2024.

SignatureTitle
/s/ JOHN W. SOMERHALDER IILYNNAE K. WILSONDirectorManager, President, and Chief Executive Officer
John W. Somerhalder IILynnae K. Wilson(Principal Executive Officer)
/s/ CHRISTOPHER A. FOSTERExecutive Vice President and Chief Financial Officer
Christopher A. Foster(Principal Financial Officer)
/s/ PETER S. WAREINGKRISTIE L. COLVINDirectorSenior Vice President and Chief Accounting Officer
Peter S. WareingKristie L. Colvin
(Duly Authorized Officer and Principal Accounting Officer)



CENTERPOINT ENERGY RESOURCES CORP.
(Registrant)
By:/s/ DARIN M. CARROLL
Darin M. Carroll
President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on February 20, 2024.

SignatureTitle
/s/ DARIN M. CARROLLChairman, President, and Chief Executive Officer
Darin M. Carroll(Principal Executive Officer and Director)
/s/ CHRISTOPHER A. FOSTERExecutive Vice President and Chief Financial Officer
Christopher A. Foster(Principal Financial Officer)
/s/ KRISTIE L. COLVINSenior Vice President and Chief Accounting Officer
Kristie L. Colvin(Duly Authorized Officer and Principal Accounting Officer)

137
201