~~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 our equity method investment in Enable, see Notes 2(c), 11 and 17 to our consolidated financial statements.~~

~~Other Operations~~

~~Our Other Operations business segment includes unallocated corporate costs and inter-segment eliminations.~~

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, 2022.

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. The FERC 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. The 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 $1.5 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 granted~~regulation by the FERC. Houston Electric is not a “public utility” under the FPA 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. The ERO and the FERC have authority to (a) impose fines and other sanctions on applicable 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 and in MISO to ReliabilityFirst Corporation. Neither Houston Electric nor Indiana Electric anticipate that the reliability standards proposed by the NERC and approved by the FERC will have a material adverse impact on their operations. To the extent that Houston Electric and 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, CenterPoint Energy isand its consolidated subsidiaries are subject to reporting and accounting requirements and isare required to maintain certain books and records and make them available for review by the FERC and state regulatory authorities in certain circumstances.

~~State and Local Regulation~~

In almost all communities in which NGD provides natural gas distribution services, it operates under franchises, certificates or licenses obtained from state and local authorities. The original terms of the franchises, with various expiration dates, typically range from 10 to 30 years, although franchises in Arkansas 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 rate regulation by the relevant state public utility commissions and, in Texas, by the Railroad Commission and those municipalities served by NGD that have retained original jurisdiction. In certain 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.

For a discussion of ~~certain of NGD’s~~the Registrants’ ongoing regulatory proceedings, see “Management’s ~~Narrative~~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~~State and Local Regulation – Electric Transmission & Distribution (CenterPoint Energy and Houston Electric)

Houston Electric is a member of ~~Transportation~~

~~In December 2006, Congress enacted~~ERCOT, which serves as the ~~2006 Act, which reauthorized~~independent system operator and regional reliability coordinator for member electric power systems in most of Texas. The ERCOT market represents approximately 90% of the ~~programs adopted~~demand for power in Texas and is one of the nation’s largest power markets. The ERCOT market operates under the ~~2002 Act. These programs included several requirements related~~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 ~~ensuring pipeline safety,~~ensure the adequacy and ~~a requirement to assess~~reliability of electricity supply across the ~~integrity~~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 ~~pipeline~~other owners of transmission facilities in ~~areas of high population concentration.~~

~~Pursuant to~~Texas, supports the ~~2006 Act, PHMSA, an agency~~operation of the ~~DOT,~~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 necessity issued ~~regulations, effective February 12, 2010, requiring operators~~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 ~~gas~~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 ~~pipelines~~system and to ~~develop~~use that system to conduct its electric delivery business and ~~implement integrity management programs similar~~for other purposes that the franchises permit. The terms of the franchises, with various expiration dates, typically range from 30 to those required for gas transmission pipelines, but tailored to reflect the differences in distribution pipelines. Operators of natural gas distribution systems were required to write and implement their integrity management programs by August 2, 2011. Our natural gas distribution systems met this deadline.40 years.

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 operations and maintenance procedures and operator qualification programs. PHMSA also updated its reporting requirements for natural gas pipelines effective January 1, 2011.

In ~~December 2011, Congress passed~~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 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 ~~2011 Act.~~same rates and other charges for transmission and distribution services. This ~~act increased~~regulated delivery charge may include the ~~maximum civil penalties~~transmission and distribution rate (which includes municipal franchise fees), a DCRF mechanism for ~~pipeline safety administrative enforcement actions; required~~recovery of incremental distribution-invested capital above that which is already reflected in the ~~DOT~~base distribution rate, a nuclear decommissioning charge associated with decommissioning the South Texas nuclear generating facility, an EECRF charge, and charges associated with securitization of regulatory assets, stranded costs and restoration costs. Transmission rates charged to ~~study~~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 ~~report on~~other charges for transmission services.

With the ~~expansion~~IURC’s approval, Indiana Electric is a member of ~~integrity management requirements~~the MISO, a FERC-approved regional transmission organization. The MISO serves the electrical transmission needs of much of the Midcontinent region and ~~the sufficiency of existing gathering line regulations to ensure safety; required pipeline operators to verify their records on maximum allowable operating pressure;~~maintains operational control over Indiana Electric’s electric transmission and imposed new emergency response and incident notification requirements. In 2016, the 2016 Act reauthorized PHMSA’s pipeline safety programs through 2019 and provided limited new authority, including the ability to issue emergency orders, to set inspection requirements for certain underwater pipelines and to promulgate minimum safety standards for natural gas storagegeneration 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 – Electric Generation (CenterPoint Energy)

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 for benefits the generation facilities provide to the transmission system. Proceeds from the sales of energy from Indiana Electric’s generation facilities that exceed the requirements of retail customers are shared by Indiana Electric and retail electric customers.

The generation facilities owned and operated by Indiana Electric are subject to various environmental regulations enforced by the EPA and the IDEM. Operations of Indiana Electric’s generation facilities are subject to regulation by the EPA and the IDEM as it pertains to the discharge of constituents from the generation facilities. For further discussion, see “Our Business — Environmental Matters” below.

For a discussion of 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 (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 ~~increased transparency into the status~~natural gas utility services are not exclusive.

Substantially all of ~~as-yet-incomplete PHMSA actions required~~CenterPoint Energy’s and CERC’s Natural Gas is subject to cost-of-service rate regulation by the ~~2011 Act.~~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.

WeFor 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)

CenterPoint Energy and CERC are subject to regulation by PHMSA under the NGPSA and the HLPSA. The NGPSA delegated to PHMSA 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 with that reauthorization comes changes to the legislative requirements that Congress sets forth for the oversight of natural gas and 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 2020 Pipes Act is a self-mandating rule for natural gas pipeline operations like CERC’s. Section 114 focuses on processes and procedures to eliminate 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 repair programs. A proposed rule is currently expected to be released by March 31, 2023.

In January 2021, PHMSA published a final rule amending the federal Pipeline Safety Regulations to ease regulatory burdens on the construction, operation, and maintenance of gas transmission, distribution, and gathering systems.

CenterPoint 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 companies~~Natural 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 by~~Pipes 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

~~Our~~The following discussion is based on environmental matters in the Registrants’ businesses as of December 31, 2022. 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 ~~our~~the 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 ~~our~~the 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 ~~our~~the Registrants’ services by directly or indirectly affecting the use or price of fossil fuels, including, but not limited to, natural gas.

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 ~~decommission~~remediate 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 in~~Increasingly, environmental regulation has ~~been to place~~resulted 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. We~~anticipated. 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 ~~our~~their business, financial position, results of operations or cash flows. In addition, wethe Registrants believe that ~~our~~their current environmental remediation activities will not materially interrupt or diminish ~~our~~their operational ability. WeThe Registrants cannot ~~assure you~~provide 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 ~~our~~the 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. ~~Some~~On August 3, 2015, the EPA released its CPP rule, which required a 32% reduction in carbon emissions from 2005 levels. The final rule was published in the Federal Register on October 23, 2015, and that action was immediately followed by litigation ultimately resulting in the U.S. Supreme Court staying implementation of the ~~proposals would~~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. The EPA has announced it plans on issuing new GHG emissions rules in the future.

The Biden administration recommitted the United States to the Paris Agreement, which can be expected to drive a renewed regulatory push to require ~~industrial sources~~further GHG emission reductions from the energy sector and proceeded to ~~meet stringent~~lead negotiations at the global climate conference in Glasgow, Scotland. On April 22, 2021, President Biden announced new ~~standards that would require substantial reductions~~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. In September 2021, CenterPoint Energy announced its net zero emissions goals for both Scope 1 and certain Scope 2 emissions by 2035 as well as a goal to reduce certain Scope 3 emissions by 20% to 30% by 2035. Because Texas is an unregulated market 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 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. ~~Our~~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 ~~our~~their operations or would have the effect of reducing the consumption of natural gas. ~~Likewise, incentives~~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 rules that target reductions in methane emissions, which are likely to ~~conserve energy or~~increase costs related to ~~use energy sources~~production, transmission and storage of natural gas. Houston Electric, in contrast to some electric utilities including Indiana Electric, does not generate electricity, other than ~~natural gas could result in a decrease in demand for our services. Conversely,~~TEEEF, and thus is not directly exposed to the risk of high capital costs and regulatory ~~actions~~uncertainties that ~~effectively promote the consumption of natural gas because of its lower~~face electric utilities that burn fossil fuels to generate electricity. CenterPoint Energy’s net zero emissions ~~characteristics would be~~goals are aligned with Indiana Electric’s generation transition plan and are expected to ~~beneficially affect us and our natural gas-related businesses. At this point in time, however, it would be speculative~~position Indiana Electric to ~~try to quantify the magnitude of the impacts from possible new~~comply with anticipated future regulatory ~~actions~~requirements related to GHG emissions ~~either positive or negative, on our businesses.~~reductions.

To the extent climate changes may occur and such climate changes result in warmer temperatures in ~~our~~the Registrants’ service territories, financial results from ~~our and Enable’s~~the Registrants’ businesses could be adversely impacted. For example, weCenterPoint Energy’s and CERC’s Natural Gas could be adversely affected through lower natural gas ~~sales~~sales. On the other hand, warmer temperatures in CenterPoint Energy’s and ~~Enable’s natural gas gathering, processing~~Houston Electric’s electric service territory may increase revenues from transmission and ~~transportation~~distribution and ~~crude oil gathering businesses could experience lower revenues.~~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 ~~our~~the 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, ~~our~~the 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, ~~our~~the Registrants’ future financial results may be adversely impacted.

Air Emissions

~~Our~~The 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 are substantially compliant with these laws and regulations.

Water Discharges

~~Our~~The 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 ~~our~~the 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 content~~EPA 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 recent decisions in the U.S. federal district courts in New Mexico and ~~it is not clear when,~~Arizona, and ~~even if, they~~on November 18, 2021, the EPA released a proposal to reestablish the pre-2015 definition of “waters of the United States” which will ~~be enacted.~~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 January 18, 2023 and becomes effective on March 20,

2023. The potential impact of ~~any new~~the revisions to the “waters of the United States” regulations on ~~our~~the Registrants’ business, liabilities, compliance obligations or profits and revenues is uncertain at this time.

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 plan for its F.B. Culley Generating Station, and Indiana Electric is currently finalizing its ELG compliance plan for the remainder of its affected units as part of its ongoing IRP process.

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 currently completing the required ecological studies and anticipates timely compliance in 2023.

Hazardous Waste

~~Our~~The 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 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 generating plants 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 are necessary to determine the remaining service life of the ponds and whether a pond must be retrofitted with liners or closed in place. Preliminary groundwater monitoring indicates potential groundwater impacts very close 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. The inability to take these extensions may result in increased and potentially significant operational costs in connection with the accelerated implementation of an alternative ash disposal system or adversely impact Indiana Electric’s future operations. Failure to comply with these requirements could also result in an enforcement proceeding, including the imposition of fines and penalties. 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. 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.

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 ~~our~~the 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 ~~14(d).~~15(d) to the consolidated financial statements.

~~EMPLOYEES~~

HUMAN CAPITAL

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 3,613 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 ~~business~~Registrant and reportable segment as of December 31, ~~2017:~~2022:


	Number of Employees			Number of Employees Represented by Collective Bargaining Groups
Reportable Segment	CenterPoint Energy	Houston Electric	CERC	CenterPoint Energy	Houston Electric	CERC
Electric	3,038	2,681	—	1,639	1,446	—
Natural Gas	3,583	—	3,296	1,691	—	1,635
Corporate and Other (1)	2,365	—	—	139	—	—
Total	8,986	2,681	3,296	3,469	1,446	1,635

Business Segment Number
Number
Represented
by Collective
Bargaining Groups
Natural Gas Distribution 3,316
1,200
Energy Services 297
—
Total 3,613
1,200
(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 3,469 employees represented by collective bargaining agreements. For information about the status of collective bargaining agreements, see Note ~~7(f)~~8(j) to ~~our~~the consolidated financial statements.

Recruiting, Training and Development.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 territories 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 vision and values 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 talent review and succession planning along with internal talent development as essential elements of overall workforce planning. 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.

CenterPoint Energy conducts annual talent review and succession planning with all levels of leadership to ensure business continuity and identify its future leaders. With regards to the senior executive team, the Board of Directors, in conjunction with management, is executing on a comprehensive executive succession planning process, which, among other things, is intended to identify and retain senior executive talent and provide development 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 offers development programs for its employees at all phases of their career including technical and leadership pathways. CenterPoint Energy’s processes and progress are reviewed annually for the purposes of 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 2022, CenterPoint Energy’s DE&I Council continued to engage employees through internal partnerships with additional resources for employee survey, training, communications and ERG governance. The DE&I Council has eight approved ERGs that focus on employee professional development, networking, cultural awareness and serve as a resource in alignment with CenterPoint Energy’s goals and objectives. The ERGs encompass groups including, but not limited to, Women, Black, LGBTQ+, Military, Hispanic/Latin, Asian, employees of Indian descent and those providing assistance to individuals of varying abilities with the support of executive leadership. The ERGs engaged over 1,600 employee members to develop and manage 59 events for the entire employee population throughout the enterprise. In 2022, CenterPoint Energy and employees were recognized by several organizations for initiatives and continued education and certification in Diversity, Equity and Inclusion. Competitive placements in 2022 were 57% racially and/or ethnically diverse and 41% gender diverse. Additional favorable metrics include the diversity of interview panels and diverse candidates interviewed. As of December 31, 2022, CenterPoint Energy’s workforce was 41% racially and/or ethnically diverse.

Compensation and Benefits. CenterPoint Energy is committed to providing its employees competitive pay and benefits. Its compensation philosophy is to maintain employee total compensation, including base pay and short-term and long-term incentives, that is market competitive, internally equitable and performance based. CenterPoint Energy believes such pay practices attract, motivate, and retain employees with the skills and competencies necessary to achieve business goals. In addition to competitive compensation, CenterPoint Energy offers its employees benefits including, health and welfare benefits, retirement and savings plans, including company matching, disability coverage, paid time off, family leave, well-being and employee assistance programs, among other benefits which CenterPoint Energy believes provides a competitive and attractive total rewards package.

Workforce Health and Safety. CenterPoint Energy is committed to the health and safety of its workforce, customers, business counterparties and the communities where it operates. Under its Safety Forward approach, safety is the responsibility of all employees. CenterPoint Energy has established a structured employee safety onboarding and development plan through its learning and development platform, offering safety and technical training courses focused on driving, worker safety and safety culture as well as other safety programs designed to encourage employee engagement and participation. Key safety metrics include advanced safety participation, leadership safety engagement rate, days away, restricted or transferred and preventable vehicle incident rate, among other metrics. CenterPoint Energy is aligned with the Edison Electric Institute, American Gas Association and other industry organizations to reduce serious injuries and fatalities. CenterPoint Energy believes the introduction of its READY model adds increased focus on hazard identification and implementation of direct controls to add capacity for safety. In response to the COVID-19 pandemic as a critical service provider, CenterPoint Energy implemented precautionary measures to keep its employees who operate its business safe and informed. Our protocols also encompassed protections for our customers as our workforce continued to provide our services.

INFORMATION ABOUT OUR EXECUTIVE OFFICERS

(as of February 9, 2023)

Name

Age

Title

David J. Lesar

Chief Executive Officer

Jason P. Wells

President, Chief Operating Officer and Chief Financial Officer

Lynne Harkel-Rumford

Executive Vice President and Chief Human Resources Officer

Monica Karuturi

Executive Vice President and General Counsel

Jason M. Ryan

Executive Vice President, Regulatory Services and Government Affairs

David J. Lesar has served as a director since May 2020 and Chief Executive Officer of CenterPoint Energy since January 2023. He previously served as President and Chief Executive Officer of the Company from July 2020 to December 2022. He served as interim Chief Executive Officer of Health Care Service Corporation, the largest privately held health insurer in the United States, from July 2019 through June 1, 2020 and a director from 2018 to July 2020. Prior to joining Health Care Services Corporation, Mr. Lesar served as the Chairman of the Board and Chief Executive Officer of Halliburton Company

from 2000 to 2017 and as its Executive Chairman of the Board from June 2017 until December 2018. Mr. Lesar joined Halliburton in 1993 and served in a variety of other roles, including executive vice president of Finance and Administration for Halliburton Energy Services, a Halliburton business unit, Chief Financial Officer of Halliburton from 1995 through May 1997 and President and Chief Operating Officer from May 1997 through August 2000. He has also served on the board of directors of several companies, most recently Agrium, Inc. as well as Lyondell Chemical Co., Southern Co., Cordant Technologies and Mirant.

Jason P. Wells has served as President, Chief Operating Officer and Chief Financial Officer of CenterPoint Energy since January 2023. He served as Executive Vice President and Chief Financial Officer of CenterPoint Energy from September 2020 to December 2022. Prior to joining CenterPoint Energy, Mr. Wells served as Executive Vice President and Chief Financial Officer of PG&E Corporation, a publicly traded electric utility holding company serving approximately 16 million customers through its subsidiary Pacific Gas and Electric Company, from June 2019 to September 2020. He previously served as Senior Vice President and Chief Financial Officer of PG&E Corporation from January 2016 to June 2019 and as Vice President, Business Finance of Pacific Gas and Electric Company 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 increasing responsibility at Pacific Gas and Electric Company. Mr. Wells earned his bachelor’s degree and master’s degree in accounting, both from the University of Florida. He is a certified public accountant. Mr. Wells serves on the Bauer College Board of the C.T. Bauer College of Business at the University of Houston, the Advisory Board of the Kinder Institute for Urban Research at Rice University, and the Boards of Central Houston, Inc. and M.D. Anderson Cancer Center.

Lynne Harkel-Rumford has served as Executive Vice President and Chief Human Resources Officer of CenterPoint Energy since January 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.

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. Karuturi 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. Ms. Karuturi also serves on the Advisory Council of the Tahirih Justice Center.

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 General Counsel from April 2019 to July 2020; as Senior Vice President, Regulatory and Government 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 Associate General Counsel from September 2014 to March 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 boards of the Lone Star Flight Museum and the Association of Electric Companies of Texas. He also serves on the executive committee of the legal committee of the American Gas Association.

Item 1A.Risk Factors

CenterPoint Energy is a holding company that conducts all of its business operations through subsidiaries, primarily Houston Electric, CERC and 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 ~~our~~the holding company and the businesses ~~and our interests in Enable.~~conducted by its subsidiaries. However, additional risks and uncertainties either not presently known or not currently believed by management to be material may also adversely affect ~~our~~CenterPoint Energy’s businesses.

~~Risk Factors Associated with Our Consolidated~~ 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

~~We are an indirect, wholly-owned subsidiary of CenterPoint Energy. CenterPoint Energy can exercise substantial control over our dividend policy~~ and ~~business and operations and could do so in a manner that is adverse to our interests.~~

~~We are managed by officers and employees of CenterPoint Energy. Our management will make determinations with respect to the following:~~

~~our payment of dividends;~~

~~our financings and our capital raising activities;~~

~~mergers or other business combinations; and~~

~~our acquisition or disposition of assets~~.

Other than the financial covenants contained in our credit facility (described under “Liquidity and Capital Resources” in Item 7 of this report), which could have the practical effect of limiting the payment of dividends under certain circumstances, there are no contractual restrictions on our ability to pay dividends to CenterPoint Energy. Our management could decide to increase our dividends to CenterPoint Energy to support its cash needs. This could adversely affect our liquidity. However, under our credit facility, our ability to pay dividends is restricted by a covenant that debt as a percentage of total capitalization may not exceed 65%.

~~If we are unable to arrange future financings on acceptable terms, our ability to refinance existing indebtedness could be limited.~~

Our businesses are capital intensive. We depend (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 commercial paper programs and (iii) on distributions from our interests in Enable to satisfy liquidity needs to the extent not satisfied by cash flow from our business operations; we may also depend on the net proceeds from a potential sale of common units we own in Enable. As of December 31, 2017, we had $2.5 billion of outstanding indebtedness on a consolidated basis. As of December 31, 2017, none of the principal amount of this debt is required to be paid through 2020. Our future financing activities may be significantly affected by, among other things:

~~general economic and capital market conditions;~~

~~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 CenterPoint Energy and the markets in which we operate;~~

~~maintenance of acceptable credit ratings by us and CenterPoint Energy;~~

~~market expectations regarding our and CenterPoint Energy’s future earnings and cash flows;~~

~~our and CenterPoint Energy’s ability to access capital markets on reasonable terms;~~

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.~~

~~Our current credit ratings are discussed in “Management’s Narrative Analysis of~~ Results of Operations — ~~Liquidity and Capital Resources — Other Matters — Impact on Liquidity of a Downgrade in Credit Ratings”~~Certain Factors Affecting Future Earnings” in Item 7, 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 lowered or withdrawn entirely by a rating agency. We note that these credit ratings are not recommendations to buy, sell or hold our securities. Each ratingwhich should be ~~evaluated independently~~read in conjunction with the risk factors contained in this Item 1A. Carefully consider each of ~~any other rating. Any future reduction~~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.

Risk Factors Affecting Operations

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

Disruptions at power generation facilities, generation inadequacy or ~~withdrawal of one or more of our credit ratings~~directives issued by regulatory authorities could ~~have a material adverse impact on our~~cause interruptions in Houston Electric’s and Indiana Electric’s ability to ~~access capital on acceptable terms.~~

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

~~Goodwill is recorded when the purchase price of a business exceeds the fair market value of the tangible~~distribution services 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~~affect their reputation, financial condition, results of operations and ~~financial condition.~~cash flows.

~~The creditworthiness~~Houston Electric owns the transmission and ~~liquidity of our parent company and our affiliates could affect our creditworthiness and liquidity.~~

~~Our credit ratings and liquidity may be impacted by the creditworthiness and liquidity of our parent company and our affiliates. As of~~ ~~December 31, 2017~~, CenterPoint Energy and its subsidiaries other than us had $50 million principal amount of debt required to be paid through 2020. This amount excludes principal repayments of approximately $1.1 billion on transition and system restoration bonds, for which dedicated revenue streams exist, and indexed debt securities obligations. If CenterPoint Energy were to experience a deteriorationdistribution infrastructure in its ~~creditworthiness~~service territory that delivers electric power to its customers, but it does not own or ~~liquidity, our creditworthiness~~operate any power generation facilities, except for its operation of TEEEF. Indiana Electric owns and ~~liquidity could be adversely affected. In~~operates power generation facilities in addition ~~CenterPoint Energy or~~to the transmission and distribution infrastructure in its ~~other subsidiaries or affiliates~~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 from time to time acquire or dispose of assets or businesses or enter into joint ventures or other transactions that could adversely impact the credit capacity, credit ratings or liquidity of CenterPoint Energy or its other subsidiaries or affiliates, which, as a result, could adversely impact our credit ratings and liquidity. Also, from time to time we and other affiliates invest or borrow funds in the ~~money pool maintained by CenterPoint Energy. If CenterPoint Energy or the affiliates that borrow any funds that we might invest from time~~future issue directives requiring members to time in the money pool were to experience a deterioration in their creditworthiness or liquidity, our creditworthiness, liquidity and the repayment of notes receivable from CenterPoint Energy and our affiliates participating in the money pool could be adversely impacted.

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 lossesimplement controlled outages as a result of ~~volatility~~an emergency or reliability issues. 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 temporary ...” for further information. If power generation capacity is severely disrupted or is inadequate for any reason in the ~~market values~~future, Houston Electric’s or ~~ineffectiveness of these contracts~~Indiana Electric’s transmission and distribution services may be diminished or ~~should a counterparty fail to perform. Additionally,~~interrupted. Further, as with the lawsuits filed in the ~~absence~~aftermath of ~~actively quoted market prices~~the February 2021 Winter Storm Event, claims and ~~pricing information from external sources,~~lawsuits could be filed against 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.

~~We derive a substantial portion of our operating income from subsidiaries through which we hold a substantial portion of our assets.~~

We derive a substantial portion of our operating income from, and hold a substantial portion of our assets through, our subsidiaries. As a result, we depend on distributions from our subsidiaries, including Enable, in order to meet our payment obligations. In general, these subsidiaries are separate and distinct legal entities and have no obligation to provide us with funds for our 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 our subsidiaries’ ability to make payments or other distributions to us,Registrants, and our ~~subsidiaries could agree to contractual restrictions on their ability to make distributions.~~

For a discussion of risks that may impact the amount of cash distributions we receive with respect to our interests in Enable, please read “— Risk Factors Affecting our Interests in Enable Midstream Partners, LP — Our cash flows will be adversely impacted if we receive less cash distributions from Enable than we currently expect.”

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

~~Risk Factors Affecting Our Natural Gas Distribution and Energy Services Businesses~~

~~Rate regulation of our business may delay or deny our ability to earn an expected return and fully recover our costs.~~

Our 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 our control. Thus, the rates that we are allowed to charge may not match our 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, ourreputation, financial condition, results of operations ~~financial condition~~ 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 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 December 2022, the A.B. Brown 1 and 2 generating units were offline at various times over an approximately week and a half period due to complications as a result of Winter Storm Elliott. If Indiana Electric is unable to meet its generation capacity it would be required to buy its energy on the open market, which is what occurred during Winter Storm Elliott when A.B. Brown 1 and 2 went offline. Such open market purchases may result in increased costs and may have an adverse impact on our operations. During the outage in Winter Storm Elliott, Indiana Electric had an increase in cost due to open market purchases because Indiana Electric would have been able to generate electricity at a lower rate than the costs incurred to purchase the electricity on the open market. 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 rates rise; 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 business. 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 is experiencing. 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 “— Continued disruptions to the supply...”

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, 2022, Houston Electric provided electric delivery service to approximately 64 REPs. Adverse economic

conditions, such as the impact of COVID-19, the February 2021 Winter Storm Event, structural problems in the market served by ERCOT, 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. 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, 2022 was $252 million. Approximately 39% and 18% 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, are 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 now preparing a new IRP to be filed in 2023 for which it has conducted a request for proposals to identify the cost of generating resources, including renewables, thermal and demand-side resources, and short-term capacity to meet the future needs of its electric customers. 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 IRP, requiring Indiana Electric to either wait for comments or proceed to 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 growth strategy, achieve financial targets, 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, we, along with our developers of the Posey solar project, have announced plans to downsize the Posey solar project from 300 MW to 191 MW because of supply chain issues experienced in the energy industry, rising cost of commodities and community feedback. Indiana Electric will also seek recovery of costs related to the amendments of the Posey agreement. For additional information, see “— Continued disruptions to the 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. In December 2022, the DOC issued its preliminary findings noting that circumvention was occurring in each of the four countries. If an affirmative finding is made by the DOC, it could impose duties on imports of solar cells and panels from Cambodia, Malaysia, Thailand and Vietnam with both forward-looking and retroactive application. 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 an affirmative finding is made by the DOC or other additional measures are imposed, our business, financial condition and results of operations may be adversely affected.

In the aftermath of the February 2021 Winter Storm Event, there have been calls for reform of 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 is in compliance with the requirements applicable to it. If any additional protections are required in the future, 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 Houston Electric’s...”

Various governmental and regulatory agencies and other entities have called for or are conducting inquiries and investigations into the February 2021 Winter Storm Event and the efforts made by various entities to prepare for, and respond to, this event, including the electricity generation shortfall issues. Such agencies and entities include the United States Congress, FERC, NERC, Texas RE, ERCOT, Texas government entities and officials such as the Texas Governor’s office, the Texas Legislature, the Texas Attorney General, the PUCT, the City of Houston and other municipal and county entities in Houston Electric’s service area, among other entities. In addition to questions around preparation and response, some federal and other officials, as well as members of the public and media, have called for reviews and reforms of the Texas electric market, including whether it should continue to be governed by ERCOT or instead be subject to FERC jurisdiction and regulation by joining an ISO such as MISO, as well as the division of the market between power generators, TDUs (such as Houston Electric) and REPs. There are significant uncertainties whether any further market structure or governance changes will result from these

discussions. 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 related 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).

If Houston Electric is otherwise unable to deploy a sufficient number of TEEEF in time to respond to a particular event; if the TEEEF 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 or their failure to perform causes or is alleged to cause any personal injury, property damage, or other damage or loss due to allegations it 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, 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 the TEEEF, and Houston Electric’s TEEEF have limited generation capacity, such that in future events customers could still be without power despite deployment of the TEEEF.

Further, the TEEEF 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. Additionally, Houston Electric’s recovery of its costs for TEEEF is not certain. In April 2022, Houston Electric sought to recover its costs for TEEEF through a DCRF application. In July 2022, Houston Electric amended its filing to include the TEEEF cost in a separate rider and intervenors filed testimony in September 2022 challenging the acquisition and deployment of TEEEF. On January 27, 2023, the administrative law judges issued a proposal for decision recommending that the leasing of the TEEEF was not prudent or reasonable and necessary and that the PUCT deny recovery of all of the TEEEF costs. The PUCT is expected to consider the proposal for decision on March 9, 2023.If Houston Electric is unable to recover any or all of its TEEEF costs, it could have an adverse impact on its financial condition, results of operations and cash flows. For further information, see “— Rate Regulation of Houston Electric’s...”, “— Our insurance coverage may not...” and “— We are subject to operational...”

Natural Gas (CenterPoint Energy and CERC)

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

~~We depend~~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 ~~NGD’s~~its customers’ needs, all of which are critical to system reliability. ~~We purchase substantially~~Substantially all of ~~NGD’s~~Natural Gas’ natural gas supply ~~from~~is purchased on intrastate and interstate pipelines. If ~~NGD~~Natural Gas 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~~Natural Gas’ requirements, the resulting decrease in ~~its~~ natural gas supply in ~~its~~Natural Gas’ service territories could have ~~a material~~an adverse effect on its financial condition, results of operations and cash ~~flows and financial condition.~~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, acts of terrorism or ~~cyber-attacks~~cyberattacks or changes in legislative or regulatory requirements, could also adversely affect ~~our business.~~Natural Gas’ businesses. Further, to the extent that ~~our~~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 ~~our NGD growth~~Natural Gas’ operations could be negatively affected.

~~Our NGD and Energy Services business, including transportation and storage, whether through the use of AMAs or other arrangements, are~~

Natural Gas is subject to fluctuations in ~~notional~~ natural gas prices, ~~as well as geographic and seasonal natural gas price differentials,~~ which could affect the ability of ~~our~~its suppliers and customers to meet their obligations or ~~otherwise~~may impact its operations which could adversely affect ~~our liquidity,~~CERC’s financial condition, results of operations and ~~financial condition.~~cash flows.

~~We are~~Natural Gas 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~~gas. Significant increases in natural gas prices, such as those experienced during the February 2021 Winter Storm Event, might affect ~~our~~Natural Gas’ ability to collect balances due from ~~our~~ customers and ~~for NGD,~~ could create the potential for uncollectible accounts expense to exceed the recoverable levels built into ~~our~~ tariff rates. In addition, a sustained period of high natural gas prices could (i) decrease demand for natural gas in the areas in which ~~we operate,~~Natural Gas operates, thereby resulting in decreased sales and revenues and (ii) increase the risk that ~~our~~Natural Gas’ suppliers or customers fail or are unable to meet their obligations. An increase in natural gas prices would also increase ~~our~~ 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 we must provide under our 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 our credit rating could result in our having to provide collateral under our shipping or hedging arrangements or to purchase natural gas, which consequently would increase our cash requirements and adversely affect our financial condition.

If our credit rating were to decline, we might be required to post cash collateral under our 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 we were experiencing significant working capital requirements or otherwise lacked liquidity, our results of operations, financial condition and cash flows could be adversely affected.

~~Our revenues and results of operations are seasonal.~~

A substantial portion of our revenues is derived from natural gas sales. Thus, our revenues and results of operations are subject to seasonality, weather conditions and other changes in natural gas usage, with revenues being higher during the winter months. Unusually mild weather in the winter months could diminish our results of operations and harm our financial condition. Conversely, extreme cold weather conditions could increase our results of operations in a manner that would not likely be annually recurring.

The states in which we provide regulated local natural gas distribution may, either through legislation or rules, adopt restrictions regarding organization, financing and affiliate transactions that could have significant adverse impacts on our ability to operate.

From time to time, proposals have been put forth in some of the states in which we do business to give state regulatory authorities increased jurisdiction 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 our ability to conduct our utility operations, to finance our 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 us to comply with competing regulatory requirements.

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

~~We compete~~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 usNatural 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 ~~our~~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 ~~marketed, sold or transported~~delivered by usNatural Gas as a result of competition with alternate energy sources may have an adverse impact on ~~our~~CenterPoint Energy and CERC’s financial condition, results of operations ~~financial condition~~ and cash flows.

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 involving natural gas pipelines.

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 usage as a result of incidents of other utilities involving natural gas pipelines, which could impact our ability to grow our customer base and our rate of growth. Growth in customer accounts and growth of customer usage each directly influence demand for electricity and natural gas 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, 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 in 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 economic 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 economic 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 effect on our financial condition, results of operations and cash flows.

Energy Systems Group (CenterPoint Energy)

Energy Systems Group’s operations could be adversely affected by a number of factors.

Energy Systems Group’s business results are dependent on a number of factors. The industry in which Energy Systems Group operates is competitive and many of the contracts are subject to a bidding process. Should Energy Systems Group be unsuccessful in bidding contracts (for example, federal Indefinite Delivery/Indefinite Quantity contracts), results of operations could be impacted. Through competitive bidding, the volume of contracted work could vary significantly from year to year. Further, to the extent there are unanticipated cost increases in completion of the contracted work or issues arise where amounts due for work performed may not be collected, the profit margin realized on any single project could be reduced. Changes in legislation and regulations impacting the sectors in which the customers served by Energy Systems Group operate could adversely impact operating results. Additionally, Energy Systems Group’s business is subject to other risks including, but not

limited to, the following: the discontinuation of the federal ESPC and UESC programs; increases in tax liability, such as due to changes in legislation or the interpretation of existing guidelines; the inability of customers to finance projects; failure to appropriately design, construct or operate projects; increased project delays and backlogs, particularly in the federal sector, increases in costs and shortages in supply materials and other factors; cancellation of projects by customers or reductions in the scope of the projects; and obligations related to warranties, guarantees and other contractual and legal obligations.

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

In the normal course of business, Energy Systems Group issues performance bonds and other forms of assurance that commit it to operate facilities, pay vendors or subcontractors and support warranty obligations. As the parent company, CenterPoint Energy or Vectren has, and will, from time to time guarantee its subsidiaries’ commitments. These guarantees do not represent incremental consolidated obligations; rather, they represent parental guarantees of subsidiary obligations to allow the subsidiary the flexibility to conduct business without posting other forms of collateral. Neither CenterPoint Energy nor Vectren has been called upon to satisfy any obligations pursuant to these parental guarantees to date. For further information, see Note 15(c) to the consolidated financial statements.

Risk Factors Affecting ~~Our Interests~~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 ~~Enable Midstream Partners, LP~~

~~We hold~~comprehensive base rate proceedings (i.e., general rate cases) based on an analysis of their invested capital, their expenses and other factors in a ~~substantial limited partner interest in Enable (54.1%~~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 ~~outstanding common units representing limited partner interests~~Registrants’ control. Houston Electric, Indiana Electric and CERC each plan to file rate cases during 2023. The Registrants can make no assurance that their or their subsidiaries respective base rate proceedings will result in ~~Enable as~~requested or favorable adjustments to their rates, in full and timely cost recovery or approval of ~~December 31, 2017), as well as 50%~~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 ~~the management rights in Enable’s general partner~~approximately $194 million and a ~~40% interest in~~10.4% ROE, but after entering into a Stipulation and Settlement Agreement filed with the ~~incentive distribution rights held by Enable’s general partner. As~~PUCT, Houston Electric received an overall revenue requirement increase of December 31, 2017, CenterPoint Energy 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 flowsapproximately $13 million 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.~~

The limited partner interests in Enable held by us and OGE are in the form of common 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 to maintain or increase the distributions on its common units. The amount of cash Enable can distribute

~~on its common 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 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 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.

~~We are not able to exercise control over Enable, which entails certain risks.~~

Enable is controlled jointly by us and OGE, who each own 50% of the management rights in the general partner of Enable. The board of directors of Enable’s general partner is composed of an equal number of directors appointed by OGE 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 that could subject us to claims that we have breached our fiduciary duty to Enable and its unitholders.~~

We 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. 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.9.4% ROE. To the extent ~~Enable is unable~~the regulatory process does not allow the Registrants 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~~make a full and timely recovery of appropriate costs, their financial ~~position,~~condition, results of operations ~~and ability to make cash distributions could be adversely affected.~~

Enable depends on a small number of customers for a significant portion of its gathering and processing revenues and its transportation and storage revenues. The loss of, or reduction in volumes from, these customers could result in a decline in sales of its gathering and processing or transportation and storage services and adversely affect its financial position, 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~~affected. Further, the ~~activities of its competitors and customers. Further, natural gas utilized as a fuel competes with other forms of energy available~~Registrants or their subsidiaries might be required 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.

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~~implement 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,measures, such as the ~~obligation to pay their share~~adoption 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~~ring-fencing measures 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 and a 40% economic interest in Enable’s general partner and CenterPoint Energy owns 100% of Enable’s Series A Preferred Units. Pursuant to the terms of the limited liability company agreement of SESH, as amended, if, at any time, CenterPoint Energy has a right to receive less than 50% of Enable’s distributions through CenterPoint Energy’s 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~~Houston Electric in connection with ~~any acquisitions or expansion capital expenditures, the payment of distributions on those~~its 2019 rate case proceeding. Such additional ~~units~~measures may ~~increase the risk that Enable will be unable to maintain or increase its per unit distribution level, which in turn may~~adversely 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~~Registrant’s businesses 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~~an adverse effect 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 itstheir financial condition, results of operations and ~~ability~~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. For example, the MPUC has ordered the amortization period for extraordinary gas costs resulting from the February 2021 Winter Storm Event be increased from 27-months to 63-months beginning on January 1, 2022, and CERC forego recovery of the associated carrying costs to make ~~distributions.~~

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

~~permit its~~customer monthly bills more affordable and due to carrying costs not being typically recoverable in Minnesota. Though several interim rate adjustment mechanisms have been approved by jurisdictional regulatory authorities and implemented by the Registrants and their subsidiaries to ~~incur or guarantee additional debt;~~

~~incur or permit~~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 ~~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~~applicable regulatory body’s approval, which we cannot assure ~~you~~would be approved, and are subject to certain limitations that ~~it will meet those ratios. In addition, Enable’s credit facilities contain events of default customary for agreements of this nature.~~

~~Enable’s~~may reduce or otherwise impede the Registrants’ or their subsidiaries ability to ~~comply with~~adjust its rates or result in rates below those requested. Therefore, the ~~covenants and restrictions contained~~Registrants can make no assurance filings for such mechanisms will result in ~~its credit facilities may be affected by events beyond its control, including prevailing economic, financial and industry conditions. If market~~favorable adjustments to rates or ~~other economic conditions deteriorate, Enable’s ability~~in full cost recovery. Further, from time to ~~comply with these covenants may be impaired. If Enable violates any~~time, the Registrants’ regulators approve the issuance 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 standardssecuritization bonds in order to ~~operate. All~~recover certain costs, including costs incurred as a result of severe weather or to recover stranded asset costs. The issuance of these ~~permits, licenses,~~securitization bonds may be delayed. For instance, CenterPoint Energy and CERC have filed for securitization of natural gas costs in Texas, received commission approval ~~limits~~ and ~~standards require~~issuance of a ~~significant amount~~financing order in 2022, and expect the Texas Public Financing Authority to issue customer rate relief bonds in first half 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 delay2023. If the issuance of such securitization bonds is delayed, we may not be able

to recover our costs in a ~~new or existing material permit or other approval, or to revoke or substantially modify~~timely manner, which could have an ~~existing permit or other approval, could adversely affect Enable’s ability to initiate or continue operations at the affected location or facility~~adverse effect on CenterPoint Energy’s and ~~on its~~CERC’s financial condition, results of operations and ~~ability~~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 ~~make cash distributions.~~

~~Additionally,~~time, these reviews and investigations have caused in ~~order to obtain permits~~certain instances, and ~~renewals of permits and other approvals~~ in the future ~~Enable may be required~~could cause, the Registrants’ to ~~prepare and present data to governmental authorities pertaining to~~recover their costs or investments below their requested levels. For example, in October 2022, the ~~potential adverse impact that any proposed pipeline or processing-related activities may have on~~MPUC issued a written order disallowing recovery of approximately $36 million of the ~~environment, individually or~~$409 million originally requested by CERC in connection with its recovery of costs incurred as a result of 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~~February 2021 Winter Storm Event. In November 2022, CERC filed a petition for reconsideration with 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,~~MPUC and the ~~cost~~MPUC issued a written order denying the petition on January 6, 2023. Notwithstanding the application 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~~such rate adjustment mechanisms, the regulatory process by which rates are determined is subject to ~~extensive federal, state~~change as a result of legislative processes or rulemakings, as the case may be, and ~~local environmental statutes, rules and regulations relating~~may not always be available or result in rates that will produce recovery of the Registrants’ or their subsidiaries’ costs or enable them to ~~air quality, water quality, waste management, wildlife conservation, natural resources and health and safety that could, among other things, delay~~earn their authorized return. Changes to the rate case 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 andinterim adjustment mechanisms could result in ~~increased compliance costs on its operations. Furthermore, if new~~an increase in regulatory lag 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 inotherwise impact 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 unableRegistrants’ ability to recover ~~these~~their costs ~~from insurance. Moreover,~~in a timely manner. To the ~~possibility exists that stricter laws, regulations or enforcement policies could significantly increase compliance costs and~~extent 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 abilityregulatory process does not allow the Registrants to make ~~cash distributions.~~

~~Hydraulic fracturing is common practice that is used by many~~a full and timely recovery 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 withinappropriate costs, 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,condition, 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~~affected. For further information on rate case proceedings and interim rate adjustment mechanisms, see “Management’s Discussion and Analysis of ~~state regulation~~Financial Condition and Results of ~~rates~~Operations — Liquidity 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~~Capital Resources — Regulatory Matters” in Item 7 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.Part II of this report.

~~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.~~regulations, including regulation of CCR,climate change legislation and certain local initiatives that seek to limit fossil fuel usage.

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 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, ~~such as:~~

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 ~~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;~~

manage wastes, including wastewater discharges, air emissions and CCR removal, and requiring remedial action or monitoring to mitigate environmental ~~conditions~~actions 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~~operations. We may need to spend substantial amounts and devote other resources from time to time ~~to:~~

~~construct~~to comply with these requirements. For example, Indiana Electric has determined that two ponds, one at F.B. Culley and one at A.B. Brown, were required to be closed under the CCR Rule. Indiana Electric has timely filed extension requests under the CCR Rule. If Indiana Electric does not receive approval of these or ~~acquire new facilities~~future extension requests, Indiana Electric may have increased and ~~equipment;~~

~~acquire permits for facility operations;~~

~~modify or replace existing~~potentially significant operational costs in connection with the accelerated implementation of an alternative ash disposal system. Further, in the course of operations we have released, and ~~proposed equipment;~~may in the future inadvertently release, various contaminants. Any such releases could have a significant impact on the environment and

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

result in significant fines. Failure to comply with ~~these~~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 ~~restore~~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 potential impact of GHGs and possible means for their regulation. The ~~recent~~ trend in environmental regulation has been to place more restrictions and limitations on activities that may impact the environment, which is expected to continue under the current administration. On April 22, 2021, President Biden announced new goals of 50% reduction of economy-wide GHG emissions and100% carbon-free electricity by 2035, which formed the basis of the United States’ commitments announced in Glasgow, Scotland. Reentry into the Paris Agreement, revised climate commitments coming out of the 2021 United Nations Climate Change Conference held in Glasgow and ~~thus~~President Biden’s executive orders may result in the development of additional regulations or changes to existing regulations. Potential future restrictions include, among other things, the United States enacting 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.~~anticipate, which could adversely affect our financial condition, results of operations and 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 facilities substantially rely on coal for their operations, certain financial institutions choose not to participate in CenterPoint Energy’s financing arrangements. 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 gas. Certain state and local governments in states such as New York and California 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.

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 (inclusive of changes related to the sale of CenterPoint Energy’s Natural Gas businesses in Arkansas and Oklahoma); regulatory approval of Indiana Electric’s generation transition plan; 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 meet 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 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, 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 and Indiana Electric and other utilities within MISO, respectively. The FERC has designated the NERC as theERO 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, 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 suggest jury verdicts and other liability have been 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 result of sales, divestitures or other 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 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

Continued 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 and is expected to continue to experience disruptions due to a multitude of factors, such as the COVID-19 pandemic, labor shortages, resource availability, long lead time, inflation and weather, 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, 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. We may continue to experience difficulties in procuring these resources and others necessary to operate our businesses in the future, and if we were to experience other

significant supply chain disruptions in the future, we may not be able to procure the resources, including labor, needed to timely perform storm restoration activities, fully execute on our ten-year capital plan or achieve our net zero emission goals. Moreover, high inflation and rising 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 its subsidiaries to meet its payment obligations and to pay dividends on its common and preferred stock, and provisions of applicable law or contractual restrictions could limit the amount of those distributions.

CenterPoint Energy derives all of its operating income from, and holds substantially all of its assets through, its 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 Indiana Gas and VEDO. As a result, CenterPoint Energy and to a lesser extent, CERC, depend on the performance of and distributions from their respective subsidiaries to meet their respective payment obligations and to pay dividends on their respective common and/or preferred stock. In general, CenterPoint Energy’s and CERC’s subsidiaries are separate and distinct legal entities and have no obligation to provide them with funds for their 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 CenterPoint Energy’s and CERC’s respective subsidiaries’ ability to make payments or other distributions to CenterPoint Energy or CERC, and their respective subsidiaries could agree to contractual restrictions on their ability to make payments or other distributions. Further, 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 base rate proceeding in late 2023. 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 any additional measures impacting CenterPoint Energy’s ability to receive dividends from Houston Electric could adversely affect CenterPoint Energy’s cash flows, credit quality, financial condition and results of operations. Any such adverse effect on CenterPoint Energy could also adversely affect Houston Electric’s cash flows, credit quality, financial condition and results of operations as CenterPoint Energy may not be able to financially support Houston Electric if and when necessary.

CenterPoint Energy’s right to receive assets of any subsidiary, and therefore the right of its creditors to participate in those assets, are structurally subordinated to the claims of that subsidiary’s creditors, including trade creditors. In addition, even if CenterPoint Energy were a creditor of any subsidiary, its 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.

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

Our businesses are capital intensive, and we rely on various sources to finance our capital expenditures. For example, we depend on (i) long-term debt, (ii) borrowings through our revolving credit facilities and, for CenterPoint Energy and CERC, commercial paper programs and (iii) if market conditions permit, issuances of additional shares of common or preferred stock by CenterPoint Energy. We may also use 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 intercompany borrowings from CenterPoint Energy that may be sourced from CenterPoint Energy’s external financings. As of December 31, 2022, CenterPoint Energy had $17 billion of outstanding indebtedness on a consolidated basis, which includes $317 million of non-recourse Securitization Bonds. For information on outstanding indebtedness of Houston Electric and CERC as well as future maturities, see Note 13 to the consolidated financial statements. Our future financing activities may be significantly affected by, among other things:

•general economic and capital market conditions, including inflation;

•credit availability from financial institutions and other lenders;

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

•the future performance of our businesses;

•maintenance of acceptable credit ratings;

•actions from the Federal Reserve, including further interest rate increases 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

•provisions of relevant securities laws.

The Registrants’ current credit ratings and any changes in credit ratings in 2022 and to date in 2023 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 reduced or withdrawn by a rating agency. The Registrants note these credit ratings are not recommendations to buy, sell or hold their securities. Each rating should be evaluated independently of any other rating. Any future reduction or withdrawal of one or more of the Registrants’ credit ratings could have an adverse impact on their ability to access capital on acceptable terms. For example, 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 collateral under its shipping 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 and cash flows could be adversely affected.

CERC also expects to receive approximately $1.1 billion in proceeds from the issuance of customer rate relief bonds by Texas Public Financing Authority in the first half of 2023 to reimburse CERC’s natural gas costs incurred as a result of the February 2021 Winter Storm Event. Such proceeds were originally expected to be received in 2022. The failure to receive such proceeds or any further delay could adversely affect our financial condition, results of operations and cash flows.

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. During the year ended December 31, 2020, CenterPoint Energy identified and recorded a goodwill impairment charge of $185 million in the Indiana Electric reporting unit. No impairments to goodwill were recorded during the years ended December 31, 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, 2022. 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 ($26 million in the aggregate, or $1.86 per ZENS, as of December 31, 2022), 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-Related Securities continues to increase by the amount of the tax benefit realized each year. If the ZENS had been redeemed on December 31, 2022, deferred taxes of approximately $665 million would have been payable in 2022, based on 2022 tax rates in effect. In addition, if all the shares of ZENS-Related Securities had been sold on December 31, 2022 to fund the aggregate redemption amount, capital gains taxes of approximately $80 million would have been payable in 2022. 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.

Dividend requirements associated with CenterPoint Energy’s Series A Preferred Stock subject it to certain risks.

CenterPoint Energy has 800,000 shares of Series A Preferred Stock outstanding. Any future payments of cash dividends, and the amount of any cash dividends CenterPoint Energy pays, on its Series A Preferred Stock will depend on, among other things, its financial condition, capital requirements and results of operations and the ability of our subsidiaries to distribute cash to CenterPoint Energy, as well as other factors that CenterPoint Energy’s Board of Directors (or an authorized committee thereof) may consider relevant. Any failure to pay scheduled dividends on the Series A Preferred Stock when due could adversely impact our ability to access capital on acceptable terms and would likely have an adverse impact on the market price of the Series A Preferred Stock, Common Stock and CenterPoint Energy’s debt securities and would prohibit CenterPoint Energy, under the terms of the Series A Preferred Stock, from paying cash dividends on or repurchasing shares of Common Stock (subject to limited exceptions) until such time as CenterPoint Energy has paid all accumulated and unpaid dividends on the Series A Preferred Stock.

Further, the terms of the Series A Preferred Stock provide that if dividends on any of the respective shares have not been declared and paid for the equivalent of three or more semi-annual or six or more quarterly dividend periods, whether or not for consecutive dividend periods, the holders of such shares, voting together as a single class with holders of any and all other series of CenterPoint Energy’s capital stock on parity with its Series A Preferred Stock (as to the payment of dividends and amounts payable on liquidation, dissolution or winding up of CenterPoint Energy’s affairs) upon which like voting rights have been conferred and are exercisable, will be entitled to vote for the election of a total of two additional members of CenterPoint Energy’s Board of Directors, subject to certain terms and limitations.

The replacement of LIBOR, or SOFR, with an alternative reference rate, may adversely affect the cost of capital related to outstanding debt and other financial instruments.

LIBOR is currently the basic rate of interest widely used as a global reference for setting interest rates on variable rate loans and other securities. Certain financial instruments entered into by the Registrants’ subsidiaries, use LIBOR as a reference rate. Beginning January 1, 2022, the Financial Conduct Authority ceased publishing one week and two-month U.S. dollar LIBOR and is expected to cease publishing all remaining U.S. dollar LIBOR tenors in June 2023 unless cessation is further extended.

Each of the Registrants’ credit and term loan facilities, including certain facilities or financial instruments entered into by their subsidiaries, use SOFR as a reference rate. Because SOFR is a broad U.S. Treasury repo financing rate that represents overnight secured funding transactions, it differs fundamentally from LIBOR. Any changes in the methods by which LIBOR is determined or regulatory activity related to LIBOR’s phaseout could cause LIBOR to perform differently than in the past or cease to exist. Changes in the method of calculating LIBOR, or the replacement of LIBOR (or SOFR) with an alternative rate or benchmark, may adversely affect interest rates and result in higher borrowing costs. This could adversely affect our cash flow and liquidity. Each of the Registrants’ credit facilities provide for a mechanism to replace SOFR with possible alternative benchmarks upon certain benchmark replacement events. We will evaluate the potential impact of any such potential benchmark replacements should it occur.

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 the Company, including our ten-year long-term capital plan, and net zero and carbon emission reduction 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 long-term 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 completed sale of our Natural Gas businesses in Arkansas and Oklahoma and the completed Enable Merger and subsequent sale of Energy Transfer Common Units and Energy Transfer Series G Preferred Units, form joint ventures or undertake restructurings, such as the recently completed 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.

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 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 2022 and 2021, the Company 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 condensed 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 corporate alternative minimum tax, and expanding federal tax credits for cleaner energy production. Based on information and forecasts as of December 31, 2022, the Registrants’ may be subject to the corporate alternative minimum tax 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 corporate alternative minimum tax 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.

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 adversaries attacking information technology systems, operational technology, network infrastructure, and other technology and facilities used to conduct almost all of our businesses, which includes, among other things, (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 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 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.

Cyberattacks, including phishing attacks and threats from the use of malicious code such as malware, ransomware and viruses, 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 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, like ERCOT and MISO, 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 operations. Because technology is increasingly complex and cyber-attacks 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, 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 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. In the second and third quarters of 2021, the TSA announced two new security directives in response to a ransomware attack on the Colonial Pipeline that occurred in 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 announced a third security directive requiring 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. Pipeline owners are required to continue to implement the measures outlined in the second directive until such time as an organization’s Cybersecurity Implementation Plan is approved. TSA approved CenterPoint Energy’s Cybersecurity Implementation Plan in December 2022. 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.

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

In connection with our businesses, we and our vendors, suppliers and contractors collect and retain personally identifiable 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 from attacks, neither program can prevent all security or privacy breaches. We and some of our third party vendors who maintain personally identifiable information have experienced, and expect to continue to experience, data privacy incidents and breaches. A significant theft, loss or fraudulent use of the personally identifiable 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.

General and Other Risks

Our revenues and results of operations are seasonal.

Houston 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, as applicable. Houston Electric’s revenues are generally higher during the warmer months. As in certain past years, unusually mild weather in the warmer months could diminish Houston Electric’s results of operations and harm its financial condition. Conversely, as in certain past years, extreme warm weather conditions could increase Houston 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 condensed financial statements for further information.

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.

A changing climate creates uncertainty and could result in broad 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. 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 by 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 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...”

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 successfully maintain or replace our aging infrastructure may be delayed or be at a greater cost than anticipated due to supply chain disruptions. Further, with respect to Natural Gas’ operations, if certain pipeline replacements (for example, cast-iron or bare steel pipe) are not completed 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 of our facilities, our insurance coverage may not be sufficient in the event a catastrophic loss is alleged to have been caused by a failure to timely complete equipment replacements. Insufficient insurance coverage and increased insurance costs could adversely impact our financial condition, results of operations and cash flows. Finally, aging infrastructure may complicate our utility operations ability to address climate change concerns and efforts to enhance resiliency and reliability. See “— Continued disruptions to the supply...”

Our financial condition, results of operations 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 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;

•failure to obtain in a timely 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.

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, certain customers may 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. Similarly to the impact of rising inflation and rising interest rates, among other items that 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, any unrecovered investment in obsolete assets. If we fail to adapt successfully to any technological change or obsolescence, fail to obtain access to important technologies or incur significant expenditures in adapting to technological change, or if implemented technology does not operate as anticipated, our businesses, financial condition, results of operations and cash flows could be adversely affected.

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 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.

~~Our operations and Enable’s operations are subject to all of the risks and hazards inherent in the gathering, processing, transportation and storage of natural gas and crude oil, including:~~

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

~~inadvertent damage from construction, vehicles, farm~~incidents that affected other utilities, such as wildfires, winter storms and ~~utility equipment;~~

~~leaks of natural gas, NGLs, crude oil and~~explosions, among other ~~hydrocarbons~~things, have exceeded or ~~losses of natural gas, NGLs and crude oil~~could exceed such utilities’ insurance coverage. Further, as a result of these recent events and incidents, the ~~malfunction of equipment~~marketplace for insurance coverage to utility companies may be unavailable or ~~facilities;~~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.

~~ruptures, fires and explosions; and~~

In common with 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 operate could have a material adverse effect on our or Enable’s operations.

~~Enable is not fully insured against all risks inherent~~companies in its ~~business. Enable currently has general liability and property insurance in place to cover certain~~line of ~~its facilities in amounts~~business that ~~Enable considers appropriate. Such policies are subject to certain limits and deductibles. Enable~~serve coastal regions, Houston Electric does not have ~~business interruption~~ insurance ~~coverage for all~~covering its transmission and distribution system, other than substations, because Houston Electric believes it to be cost prohibitive and insurance capacity to be limited. Historically, Houston Electric has 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 ~~operations. Insurance coverage~~regulated rates or otherwise. In the future, any such recovery may not be ~~available in the future at current costs or on commercially reasonable terms, and the insurance proceeds received for~~granted. Therefore, Houston Electric may not be able to restore any loss

of, or ~~any~~ damage to, any of ~~Enable’s facilities may not be sufficient to restore the loss or damage~~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 threat is 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:

•reduced demand from our commercial and industrial customers and shifts in demand for our services;

•delay the timeliness of our service to customers because of shutdowns and/or illness and travel restrictions among our employees;

•negatively impact the financial condition of our customers and REPs and their ability to ~~make cash distributions.~~pay for our services, and our ability to disconnect service for non-payment may be limited, and state regulators may impose bill deferral programs;

~~We and CenterPoint Energy could incur liabilities associated with businesses and assets that we have transferred~~•may limit or curtail significantly or entirely the ability of public utility commissions to ~~others.~~

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

merchant energy, energy trading and retail electric provider 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 Californiaauthorize applications and other ~~markets (the last remaining case involving CenterPoint Energy is now~~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 cyber attacks 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 ~~appeal, following~~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 ~~district court’s summary judgment in favor of CES, our subsidiary) and various asbestos~~above and other ~~environmental matters that arise~~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. In June 2017, GenOn and various affiliates filed for protection under Chapter 11 of~~time with the ~~U.S. Bankruptcy Code. In December 2017, GenOn received court approval of~~SEC. We might not be able to predict or respond to all impacts on a ~~restructuring plan and is expected~~timely basis to ~~emerge from Chapter 11 in mid-2018. We and CenterPoint Energy submitted proofs of claim in the bankruptcy proceedings~~prevent near- or long-term adverse impacts 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, CenterPoint Energy or Houston Electric could incur liability and be responsible for satisfying the liability.

In connection with Houston Electric’s sale of Texas Genco, the separation agreement was amended to provide that Texas Genco would no longer be liable for, and Houston Electric 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 Houston Electric, and in certain of the asbestos lawsuits Houston Electric has agreed to continue to defend such claims to the extent they are covered by insurance maintained by Houston Electric, 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, 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. 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~~liquidity. The ultimate impact of public health threats on our ~~facilities or perform certain corporate functions.~~

~~Our performance~~business depends on factors beyond our knowledge or control, including the ~~successful operation~~duration and severity of ~~our facilities. Operating~~the outbreak as well as third-party actions taken to contain the spread and mitigate the public health effects. Any of 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.~~

~~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~~factors could have a ~~material adverse effect~~negative impact on our business, outlook, financial condition and results of operations, ~~financial condition and/or cash flows.~~which impact could be material.

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 is~~businesses 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 ~~ability to recruit, retain,~~employee population, not including employees of Energy Systems Group or temporary employees, 19.3%, 23.6% and ~~motivate employees.~~26.1% were retirement eligible as of December 31, 2022, 2021 and 2020, 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, our 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. 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, 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 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 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 NGD has 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 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.

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.

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

Certain of our 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 us 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 our and Enable’s operations. Both we 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 us 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 us 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 we 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. We 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. We 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 depends~~depend on good labor relations with our ~~employees.~~

~~Several~~employees, and several of our businesses ~~have entered into and~~ have in place collective bargaining agreements with different labor ~~unions.~~unions, comprising approximately 39% of our workforce. We have ~~six~~several separate bargaining units, each with a unique collective bargaining ~~agreement. In 2017, we entered into renegotiated~~agreement described further in Note 8(j) to the consolidated financial statements, which information is incorporated herein by reference. The collective bargaining agreements with ~~United Steelworkers Local 227~~IBEW 1393, USW 12213, USW 7441 related to Natural Gas employees and ~~United Steelworkers Local 13-1, which~~IBEW 66 related to Houston Electric employees are scheduled to expire in ~~June and July of 2022, respectively. The collective bargaining agreements with Gas Workers Union Local 340 and~~May 2023 for IBEW ~~Local 949 are each scheduled to expire in 2020,~~66 and the ~~collective bargaining agreements with Professional Employees International Union Local 12~~remainder are scheduled to expire in ~~2021.~~December 2023, and negotiations of these agreements are expected to be completed before the 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 material~~an 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 material~~an adverse effect on our businesses, results of operations ~~and/or cash flows.~~

~~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 in 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 expenditures so that we can continue to provide cost-effective and reliable methods of energy delivery.

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 technologies or incur significant expenditures in adapting to technological change, or if implemented technology does not operate as anticipated, our businesses, operating results, financial condition and cash flows 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 14 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. Prolonged economic downturns that negatively impact our results of operations and cash flows could result in future material impairment charges to write-down the carrying value of certain assets, including goodwill, to their respective fair values.

For example, we conduct business 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 natural gas 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 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.

Item 1B.Unresolved Staff Comments

If we fail to maintain an effective system of internal controls, our ability to accurately report our financial condition, results of operations or cash flows or prevent fraud may be adversely affected. As a result, investors could lose confidence in our financial reporting, which could impact our businesses and the trading price of our securities.

None.

Effective internal controls are necessary for us to provide reliable financial reports, effectively prevent fraud and operate successfully as a public company. If our efforts to maintain an effective system of internal controls are not successful, we are unable to maintain adequate controls over 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

Item 2.Properties

The following discussion is based on the ~~trading price~~Registrants’ businesses as of ~~our securities.~~December 31, 2022.

~~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 CenterPoint Energy’s Ethics and Compliance Code and Standards of Conduct/Business Ethics policy, among 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 a material adverse effect on our results of operations, financial condition and cash flows.

~~Item 1B.~~ ~~Unresolved Staff Comments~~

~~None.~~

~~Item 2.~~ ~~Properties~~

Character of Ownership

We lease or own our principal properties in ~~fee.~~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 (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 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 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 related 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 Indiana 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.

Electric Lines - Transmission and Distribution. As of December 31, 2022, Houston Electric and Indiana Electric owned and operated the following electric transmission and distribution lines:


	Houston Electric		Indiana Electric
Description	Overhead Lines	Underground Lines	Indiana	Kentucky (1)
Transmission lines:	(in Circuit Miles)
69 kV	213	2	566	—
138 kV	2,290	24	407	9
345 kV	1,445	—	48	15
Total	3,948	26	1,021	24

	(in Circuit Miles)
Distribution lines	29,057	28,611	4,615	2,583

(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. As of December 31, 2022, Indiana Electric had 1,212 MW of installed generating capacity, as set forth in the following table.


Generation Source	Unit No.	Location	Date in Service	Capacity (MW)
Coal
A.B. Brown (1)	1	Posey County	1979	245
A.B. Brown (1)	2	Posey County	1986	240
F.B. Culley	2	Warrick County	1966	90
F.B. Culley	3	Warrick County	1973	270
Warrick (2)	4	Warrick County	1970	150
Total Coal Capacity				995
Gas
Brown (3)	3	Posey County	1991	80
Brown	4	Posey County	2002	80



Renewable Landfill Gas		Pike County	2009	3
Total Gas Capacity				163

Generation Source

Unit No.

Location

Date in Service

Capacity
(MW)

Solar

Oak Hill

Evansville, Indiana

2018

Volkman

Evansville, Indiana

2018

Troy

Spencer County

2021

Total Solar Capacity

Total Generating Capacity (4)

1,212

(1)A.B. Brown Units 1 & 2 are expected to be retired by the end of 2023.

(2)SIGECO and AGC own a 300 MW unit at the Warrick Power Plant as tenants in common.

(3)Brown Unit 3 is also equipped to burn oil.

(4)Excludes 1.5% participation in OVEC. See Item 1. Business for more details.

Natural Gas ~~Distribution~~

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, ~~regarding the properties~~see “Management’s Discussion and Analysis of ~~our Natural Gas Distribution business segment, please read “Business~~Financial Condition and Results of Operations — ~~Our Business~~Liquidity and Capital Resources — ~~Natural Gas Distribution — Assets”~~Regulatory Matters” in Item 17 of Part II of this report, which ~~information~~discussion is incorporated herein by reference.

~~Energy Services~~

Solar. Indiana Electric entered into a BTA to build a 300 MW solar array in Posey County, Indiana, which was subsequently downsized to 191 MW. 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 properties~~about Indiana Electric’s BTA’s, see “Management’s Discussion and Analysis of ~~our Energy Services business segment, please read “Business~~Financial Condition and Results of Operations — ~~Our Business~~Liquidity and Capital Resources — ~~Energy Services — Assets”~~Regulatory Matters” in Item 17 of Part II of this report, which ~~information~~discussion is incorporated herein by reference.

~~Midstream Investments~~Mobile Generation. As allowed by a law enacted by the Texas legislature after the February 2021 Winter Storm Event, Houston Electric is leasing TEEEF that can aid in restoring power to customers during certain widespread power outages that are impacting its distribution system. As of December 31, 2022, Houston Electric leased 505 MW of TEEEF. For more information, see Note 20 to the consolidated financial statements.

~~For information regarding~~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 ~~properties~~interface between the transmission system and the distribution grid.


	As of December 31, 2022
	Number of Substations	Transformer Capacity (in Mva)
Houston Electric	239	72,050
Indiana Electric	110	6,906
Total CenterPoint Energy	349	78,956

Service Centers. Service centers consist of ~~our Midstream Investments~~office buildings, warehouses and repair facilities that are used in the business ~~segment, please read “Business — Our Business — Midstream Investments”~~of transmitting and distributing electricity.


	As of December 31, 2022
	Number of Service Centers	Acres of Land
Houston Electric	13	320
Indiana Electric	6	50
Total CenterPoint Energy	19	370

Natural Gas (CenterPoint Energy and CERC)

CenterPoint 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 ~~Item 1~~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 ~~this report,~~December 31, 2022, CenterPoint Energy’s and CERC’s Natural Gas owned and operated the following natural gas facilities:


	No. of Assets	Storage Capacity (Bcf)	Working Capacity (Bcf)	Maximum Daily Withdrawal Rate (MMcf)
CenterPoint Energy
Underground Natural Gas Storage Facility	8	43	14	331
CERC
Underground Natural Gas Storage Facility	5	32	9	205


			On-site Storage Capacity
	No. of Assets	Daily Production Rate (Dth)	Millions of Gallons	Dth
CenterPoint Energy and CERC
Propane Air-Gas Manufacturing Plant	16	234,000	14,100,000	1,290,000
LNG Plant Facility	1	72,000	12,000,000	1,000,000

The table below reflects CenterPoint Energy’s and CERC’s Natural Gas contracted upstream storage services as of December 31, 2022:


	Storage Capacity (Bcf)	Maximum Peak Daily Delivery (MMcf)

Upstream Storage Service	92	2,322

As of December 31, 2022, CenterPoint Energy’s and CERC’s Natural Gas owned approximately 84,000 and 81,000 linear miles, respectively, of natural gas distribution and transmission mains, respectively, varying in size from one-half inch to 24 inches in diameter. CenterPoint Energy’s and CERC’s Natural Gas in Indiana and Ohio includes approximately 22,000 and 19,000 miles, respectively, of distribution and transmission mains, all of which ~~information is incorporated herein~~are located in Indiana and Ohio except for, in the case of CenterPoint Energy, 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 ~~reference.~~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, 2022, CenterPoint Energy and CERC, through CEIP, owned and operated over 217 miles of intrastate pipeline in Louisiana and Texas.

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 ~~Narrative~~Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Regulatory Matters” in Item 7 of this report and Note ~~14(d)~~15(d) to ~~our~~the consolidated financial statements, which information is incorporated herein by reference.

Item 4.Mine Safety Disclosures

Not applicable.

PART II

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

~~All~~CenterPoint Energy

As of February 9, 2023, CenterPoint Energy’s common stock was held by approximately 23,939 shareholders of record. CenterPoint Energy’s common stock is listed on the NYSE and Chicago Stock Exchange and is traded under the symbol “CNP.”

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

Repurchases of Equity Securities

During the quarter ended December 31, 2022, none of CenterPoint Energy’s equity securities registered pursuant to Section 12 of the Securities Exchange Act of 1934 were purchased by or on behalf of CenterPoint Energy or any “affiliated purchasers,” as defined in Rule 10b-18(a)(3) under the Securities Exchange Act of 1934.

Houston Electric

As of February 9, 2023, all of Houston Electric’s 1,000 outstanding common shares ~~of our common stock are~~were held by Utility Holding, LLC, a wholly-owned subsidiary of CenterPoint Energy.

~~We paid dividends~~CERC

As of ~~$601 million, $643 million and $43 million to our parent in 2017, 2016 and 2015, respectively.~~February 9, 2023, 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.

~~Our revolving credit facility limits our debt as a percentage of total capitalization to 65%. This covenant could restrict our ability to distribute dividends.~~

Item 6. Selected Financial Data (CenterPoint Energy)

~~The information called for by Item 6 is omitted pursuant to Instruction I(2) to Form 10-K (Omission of Information by Certain Wholly-Owned Subsidiaries).~~Not applicable.

Item 7.Management’s ~~Narrative~~Discussion and Analysis of Financial Condition 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 ~~narrative~~combined discussion and analysis should be read in combination with ~~our~~the consolidated financial statements ~~and notes contained~~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 ~~report.~~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 are~~CenterPoint Energy, Inc. is a public utility holding company. CenterPoint Energy’s operating subsidiaries own and operate electric transmission, distribution and generation and natural gas distribution facilities, and provide energy performance contracting and sustainable infrastructure services. For a detailed description of CenterPoint Energy’s operating subsidiaries, please read Note 1 to the consolidated financial statements.

Houston Electric is an indirect, wholly-owned subsidiary of CenterPoint Energy ~~a public utility holding company. Our operating subsidiaries own~~that provides electric transmission service to transmission service customers in the ERCOT region and ~~operate natural gas~~ distribution ~~facilities, supply natural gas~~service to ~~commercial and industrial customers and electric and natural gas utilities and own interests in Enable as described below. Our operating subsidiaries include:~~REPs serving the Texas gulf coast area that includes the city of Houston.

~~NGD, which~~CERC Corp. 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 variable~~VEDO, owns and ~~fixed-price physical~~operates natural gas ~~supplies~~distribution systems in Indiana and ~~services primarily to commercial~~Ohio, respectively, and ~~industrial customers~~(iii) owns and ~~electric~~operates 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 approximately 54.1% of~~CenterPoint Energy completed the ~~limited partner~~Restructuring on June 30, 2022, whereby the equity interests in ~~Enable, an unconsolidated partnership jointly controlled~~Indiana Gas and VEDO, both subsidiaries it acquired in its acquisition of Vectren on February 1, 2019, were transferred from VUH to CERC Corp. As a result, Indiana Gas and VEDO became wholly owned subsidiaries of CERC Corp. to better align CenterPoint Energy’s organizational structure with ~~OGE,~~management and financial reporting and to fund future capital investments more efficiently. The Restructuring was a non-cash common control acquisition by CERC. As a result, CERC acquired these businesses at CenterPoint Energy’s historical basis in these entities and prior year amounts were recast to reflect the Restructuring as if it occurred at the earliest period presented for which ~~owns, operates~~CenterPoint Energy had common control. The Restructuring did not impact CenterPoint Energy’s carrying basis in any entity, its allocation of goodwill to its reporting units, or its segment presentation. Neither CenterPoint Energy nor CERC recognized any gains or losses in connection with the Restructuring. SIGECO was not acquired by CERC and ~~develops natural gas and crude oil infrastructure assets.~~ remains a subsidiary of VUH.

~~Business~~Reportable Segments

In this ~~section,~~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. Our natural gas~~subject, among other factors.

As of December 31, 2022, 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 ~~also~~ subject to rate regulation in Houston Electric’s and ~~are reported~~Indiana Electric’s service territories, as well as the impacts of generation-related stranded costs and other true-up balances recoverable by the regulated electric utility and energy delivery services to electric customers and electric generation assets to serve electric customers and optimize those assets in the ~~Natural Gas Distribution business segment.~~wholesale power market in Indiana Electric’s service territory. For further information about ~~our~~the Electric reportable segment, see “Business — Our Business — Electric” in Item 1 of Part I of this report.

•The Natural Gas ~~Distribution business~~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 to customers in Minnesota and home repair protection plans to natural gas customers in Indiana, Mississippi, Ohio and Texas through a third party. For further information about the Natural Gas reportable 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 ~~transportation and storage~~sustainable infrastructure services ~~for commercial 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~~corporate support operations that support CenterPoint Energy’s business operations. CenterPoint Energy’s Corporate and Other ~~Operations~~also includes office buildings and other real estate used for business ~~segment includes unallocated corporate costs~~operations.

Houston Electric and ~~inter-segment eliminations.~~CERC each consist of a single reportable segment.

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 transmission and delivery of electricity and the sale of natural gas by our subsidiaries. ~~To assess~~

In 2021, we announced strategic goals for our ~~financial performance,~~businesses, including our ~~management primarily monitors operating income~~ten-year capital plan, and ~~cash flows from our business segments. Within these broader financial measures, we monitor margins, operation~~net zero 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 to the operation of our business segments, including the number of customers, throughput, use per customer, commodity prices and heating 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, we conduct business 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. 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 impactcarbon emission reduction goals. Our focus on the growth ~~rate~~ of our ~~customer base~~regulated utility businesses led to the previously announced Enable Merger in December 2021 and ~~overall demand. Also, adverse economic conditions, coupled with concerns for protecting the environment~~CenterPoint Energy’s subsequent complete divestiture of its remaining Energy Transfer Common Units and ~~increased availability~~Energy Transfer Series G Preferred Units in February and March 2022. As a result of ~~alternate energy sources, may cause consumers to use less energy or avoid expansions of their facilities, resulting in less demand for our services.~~

~~Performance~~these transactions, over 95% of our ~~Natural Gas Distribution~~earnings are now derived from regulated utility operations. See Note 11 to the consolidated financial statements for further details.

Pursuant to this business segment 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~~strategy and in ~~October-November, resulting in a year that was warmer by a tenth~~light 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, NGD has utilized weather hedges to help reduce the impact of mild weather on its financial results. 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 our businesses is influenced significantly by the regulatory treatment we receive from the various state and local regulators who set NGD’s rates.

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. While this business utilizes financial derivatives to mitigate 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, as reflected in our current capital plan, which was increased in 2022 to fund additional investments in system resiliency, reliability, and grid modernization, is required. 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, including via increased electric vehicle adoption. 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), and issuances of debt ~~and equity~~ 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 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 rising interest rates can also affect the availability of new capital on terms we consider attractive. In those circumstances, ~~companies like us~~we 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 safety~~applicable regulations, CenterPoint Energy, Houston Electric and ~~integrity regulations, we~~CERC are making, and will continue to make, significant capital investments in ~~our~~their service territories ~~which are necessary~~under our capital plan to help operate and maintain a ~~safe,~~safer, more reliable and growing electric and natural gas ~~system. Our~~systems. The current economic environment (e.g., increasing interest rates, higher relative levels of inflation in the United 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. This increased level of scrutiny could result in the disallowance (in part or in whole) of CenterPoint Energy and its subsidiaries from recovering on certain capital investments. CenterPoint Energy’s, Houston Electric’s and CERC’s compliance expenses may also increase as a result of preventative measures required under these regulations. Consequently, new rates in the areas wethey serve are necessary to recover

these increasing costs.

~~Consistent with the regulatory treatment~~ Houston Electric, Indiana Electric and CERC plan to file rate cases during 2023. The outcome of ~~such costs, we defer the amount of pension expense that differs from the level of pension expense included in our~~these base ~~rates for our 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~~rate proceedings is uncertain 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 to~~may be impacted by the current economic environment.

To assess our financial performance, our management primarily monitors the recovery of costs and return on investments by the evaluation of net income and capital expenditures, among other things, from our regulated service territories within our reportable segments. Within these broader financial measures, we monitor margins, natural gas and fuel costs, interest expense, capital spend, working capital requirements, and operation and maintenance expense. In addition 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 prices, heating and cooling degree days, environmental impacts, safety factors, system reliability and customer satisfaction.

Each state has a unique economy and is driven by different industrial sectors. Our largest customers reflect the diversity 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 ~~affecting~~indicate customers have reduced their energy consumption, which could adversely affect our results. To the ~~midstream~~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, ~~discussed below. Enable’s outlook~~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 ~~based~~approximately 1%. Management expects residential meter growth for CERC to remain in line with long term trends at approximately 1%.

Rising inflation and interest rates and a recessionary environment could potentially adversely impact CenterPoint Energy’s ability to execute on its ~~management’s assumptions regarding~~10-year capital plan. The inability to execute on our capital plan may result in lost 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 ~~impact~~global supply chain has experienced significant disruptions due to a multitude of ~~these trends that it has developed by interpreting~~factors, such as labor shortages, resource availability, long lead times, inflation and weather. These disruptions have adversely impacted the ~~information currently available~~utility industry. Like many of our peers, we have experienced disruptions to ~~them. If Enable management’s assumptions or interpretation~~our supply chain and may continue to experience such disruptions in the future. For example, we, along with the developer of ~~available information prove~~the project, announced plans in January 2022 to downsize the solar array to be ~~incorrect, Enable’s future~~built in Posey County, Indiana due to supply chain issues experienced in the energy industry, rising cost of commodities and community feedback. 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 ~~condition~~statements.

Further, in response to concerns for protecting the environment, we have strived to take a leading stance in the transition to safer and ~~results of operations may differ materially from~~cleaner energy by being the first combined electric and natural gas utility with regulated generation assets to adopt net zero for its ~~expectations.~~

~~Enable’s business is impacted~~Scope 1 and certain Scope 2 GHG emissions by ~~commodity prices, which have declined~~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 ~~otherwise experienced significant volatility in recent years. Commodity prices impact the drilling and production~~commercial customers reduce GHG emissions attributable to their end use of natural gas ~~and crude oil in the areas served~~ by Enable’s systems, and the volumes on Enable’s systems are negatively impacted if producers decrease drilling and production in those areas served. Both Enable’s gathering and processing segment and its transportation and storage segment can be impacted20% to 30% by ~~drilling and production.~~2035 from a 2021 baseline. Our capital plan supports these goals.

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. In addition, Enable’s processing arrangements expose it to commodity price fluctuations. Enable has attempted to mitigate the impact of commodity prices on 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. As a result, the proven reserves of natural gas and crude oil in the U.S. have significantly increased.

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.~~ 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. For the impactsRegulatory Proceedings. The commissioners of the ~~tax reform legislation, see Note 13~~MPUC held deliberations in August 2022 regarding CERC’s natural gas cost prudency review case related to ~~our consolidated financial statements.~~

~~Hurricane Harvey.~~ ~~NGD suffered damage as~~the February 2021 Winter Storm Event. As a result, the MPUC disallowed recovery of ~~Hurricane Harvey, which struck~~approximately $36 million of jurisdictional gas costs incurred during the ~~Texas coast~~event (or about 8.7% of the total of such costs incurred by CERC) and CERC’s regulatory asset balance was reduced to reflect the disallowance. Houston Electric filed its DCRF application with the PUCT on ~~Friday, August 25, 2017.~~April 5, 2022, and subsequently amended such filing on July 1, 2022 to show mobile generation in a separate Rider TEEEF, seeking recovery of deferred costs and the applicable return as of December 31, 2021 under these lease agreements of approximately $200 million. The annual revenue increase requested for these lease agreements is

approximately $57 million. On January 27, 2023, the administrative law judges issued a proposal for decision recommending that the leasing of the TEEEF was not prudent or reasonable and necessary and that the PUCT deny recovery of all of the TEEEF costs. The PUCT is expected to consider the proposal for decision on March 9, 2023. For further information, ~~regarding the impact of Hurricane Harvey,~~ see Note 67 to ~~our~~the consolidated financial statements.

~~Regulatory Proceedings.~~ For ~~details~~information related to our pending and completed regulatory proceedings ~~during 2017,~~to date in 2022 and to date in 2023, see “—Liquidity and Capital Resources —Regulatory Matters” below.

Debt Transactions. In ~~2017, we retired~~2022, Houston Electric issued $1.6 billion, and CERC issued or borrowed $1.0 billion in new debt, excluding the debt exchanges discussed below. CenterPoint Energy repaid or redeemed a combined ~~$550~~$1.53 billion of debt, including CERC’s redemption of $425 million of debt and CEHE’s redemption of $500 million of debt, but excluding scheduled principal payments on Securitization Bonds. For information about debt transactions in 2022, see Note 13 to the consolidated financial statements.

Debt Exchange. As a part of the Restructuring, on May 27, 2022, CERC Corp. and VUH completed an exchange with holders of VUH PPNs whereby CERC Corp. issued new senior notes with an aggregate principal amount of $302 million in return for all of their outstanding VUH PPNs with an aggregate principal amount of $302 million. On October 5, 2022, in connection with the settlement of an exchange offer, CERC Corp. issued $75 million aggregate principal amount of 6.10% senior ~~notes. Additionally, we issued $300 million aggregate principal amount of unsecured~~notes due 2035 in exchange for all remaining outstanding VUH senior notes. For ~~further~~additional information, ~~about our 2017 debt transactions,~~ see Note 1213 to ~~our~~the consolidated financial statements.

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

Credit Facilities. On December 6, 2022, CenterPoint Energy, Inc. and its wholly owned subsidiaries, Houston Electric and CERC, replaced their existing revolving credit facilities with three revolving credit facilities totaling $3.75 billion in aggregate commitments. In ~~June 2017, we~~addition, SIGECO entered into ~~an amendment to our respective~~a new revolving credit facility ~~to (a) extend~~totaling an additional $250 million in aggregate commitments. The aggregate amount of commitments among the ~~termination date~~four credit facilities total $4.0 billion. On June 30, 2022, in connection with the Restructuring, VUH repaid in full all outstanding indebtedness and ~~terminate the swingline loan subfacility,~~terminated all remaining commitments and ~~(b) increase the aggregate commitments~~other obligations under ~~such facility.~~its $400 million amended and restated credit agreement dated as of February 4, 2021. For ~~further~~additional information, ~~about our 2017 credit facility amendment,~~ see Note 1213 to ~~our~~the consolidated financial statements.

~~AEM Acquisition.~~Sale of Energy Transfer Equity Securities. In ~~January 2017, CES acquired AEM.~~2022, CenterPoint Energy sold its remaining Energy Transfer Common Units and Energy Transfer Series G Preferred Units for net proceeds of $702 million. For more information, see Note 11 to the consolidated financial statements.

Sale of Natural Gas Businesses. On January 10, 2022, CERC Corp. completed the sale of its Arkansas and Oklahoma Natural Gas businesses. For additional information regarding ~~this acquisition,~~discontinued operations and divestitures, see Note 4 to ~~our~~the 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 ~~performance~~Restructuring, joint ventures and acquisitions or dispositions of ~~Enable,~~assets or businesses, including the ~~amount of cash distributions we receive from Enable, and the value~~completed sale of our ~~interest~~Natural Gas businesses in ~~Enable,~~Arkansas and ~~factors that may~~Oklahoma and our exit of the midstream sector, which we cannot assure will have ~~a material impact on such performance, cash distributions and value, including factors such as:~~


◦	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;~~

the anticipated benefits to us;

•industrial, commercial and residential growth in our service territories and changes in market demand, including the demand for our non-utility products and services and 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 recovery of costs and a reasonable return on ~~investment;~~investment, including the timing and amount of the recovery of Houston Electric’s TEEEF leases;

•future economic conditions in regional and national markets, including inflation, and their effect on sales, prices and costs;

•weather variations and other natural phenomena, including the impact of severe weather events on operations and ~~capital;~~capital, such as impacts from the February 2021 Winter Storm Event;

•increases in commodity prices;

•volatility in the markets for natural gas as a result of, among other factors, armed conflicts, including the conflict in Ukraine and the related sanctions on certain Russian entities;

•changes in rates of inflation;

•continued disruptions to the global supply chain, including 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 REPs to satisfy their obligations to CenterPoint Energy and Houston Electric, including the negative impact on such ability related to adverse economic conditions and severe weather events;

•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 behaviors 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;

tax reform and legislation, including the effects of the TCJA 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;~~

~~the timing and extent of changes in commodity prices, particularly natural gas, and the effects of geographic and seasonal commodity price differentials;~~

problems with regulatory approval, construction, implementation of necessary technology or other issues with respect to major capital projects that result in delays or in cost overruns that cannot be recouped in rates;

~~local, state and federal legislative and regulatory actions or developments relating to the environment, including those related to global climate change;~~

~~the impact of unplanned facility outages;~~

~~any~~ •direct or indirect effects on our ~~or Enable’s~~ facilities, resources, operations and financial condition resulting from terrorism, ~~cyber-attacks,~~cyber attacks 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 legislation, including the effects of the CARES Act and the IRA (which includes but is not limited to any potential changes to tax rates, tax credits and/or interest deductibility), as well as any changes in tax laws under the current administration, and uncertainties involving state commissions’ and local municipalities’ regulatory requirements and determinations regarding the treatment of EDIT and our rates;

•our ability to ~~invest planned capital~~mitigate weather impacts through normalization or rate mechanisms, and the ~~timely recovery~~effectiveness of ~~our investment in capital;~~such mechanisms;

~~our ability to control operation and maintenance costs;~~

•actions by credit rating ~~agencies;~~agencies, including any potential downgrades to credit ratings;

•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 overruns 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, 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 or other closures;

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

•the ~~investment performance~~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;

•impacts from CenterPoint ~~Energy, Inc.’s~~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 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, 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;~~

~~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, such as the anticipated issuance of customer rate relief bonds by the Texas Public Financing Authority, for any hurricanes or other severe weather events, or natural disasters or other recovery of costs, ~~associated any future hurricanes or natural disasters,~~ including ~~costs associated with Hurricane Harvey;~~stranded coal 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;~~industry, including the ability to successfully complete merger, acquisition and divestiture plans;

•our ~~or Enable’s~~ ability to recruit, effectively transition and retain management and key employees and maintain good labor relations;

•changes in technology, particularly with respect to efficient battery storage or the ~~ability~~emergence or growth of ~~GenOn (formerly known as RRI Energy, Inc., Reliant Energy~~new, developing or alternative sources of generation, and ~~RRI), a wholly-owned subsidiary~~their adoption by consumers;

•the impact of ~~NRG,~~climate change and ~~its subsidiaries, currently~~alternate energy sources on the ~~subject of bankruptcy proceedings, to satisfy their obligations to us, including indemnity obligations;~~demand for natural gas and electricity generated or transmitted by us;

~~the outcome of litigation;~~

•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 current administration;

•the transition to a replacement for the LIBOR benchmark interest rate;

•CenterPoint Energy’s ability to execute on its 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 development of new opportunities and the performance of projects undertaken by Energy Systems Group, which are subject to, among other factors, the level of success in bidding contracts and cancellation and/or reductions in the scope of projects by customers, and obligations related to warranties, guarantees and other contractual and legal obligations;

•the effect of changes in and application of accounting standards and pronouncements; and

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

CENTERPOINT ENERGY CONSOLIDATED RESULTS OF OPERATIONS

~~Our~~CenterPoint Energy’s results of operations are affected by seasonal fluctuations in the demand for electricity and natural gas. CenterPoint Energy’s results of operations are also affected by, among other things, the actions of various governmental authorities having jurisdiction over rates its subsidiaries charge, debt service costs, income tax expense, its subsidiaries ability to collect receivables from REPs and customers and its ability to recover its regulatory assets. For information regarding factors that may affect the future results of our consolidated operations, please read “Risk Factors” in Item 1A of Part I of this report.

Income (loss) available to common shareholders for the years ended December 31, 2022, 2021 and 2020 was as follows:


	Year Ended December 31,						Favorable (Unfavorable)
	2022		2021		2020		2022 to 2021		2021 to 2020
	(in millions)
Electric	$	603	$	475	$	230	$	128	$	245
Natural Gas	492		403		278		89		125
Total Utility Operations	1,095		878		508		217		370

Corporate & Other (1)	(87)		(305)		(201)		218		(104)
Discontinued Operations	—		818		(1,256)		(818)		2,074
Total CenterPoint Energy	$	1,008	$	1,391	$	(949)	$	(383)	$	2,340

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

2022 Compared to 2021

Net Income. CenterPoint Energy reported income available to common shareholders of $1,008 million for 2022 compared to income available to common shareholders of $1,391 million for 2021.

Income available to common shareholders decreased $383 million primarily due to the following items:

•an increase in net income of $128 million for the 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 Other, primarily due to a $28 million pre-tax payment related to the 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 the 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 preferred shareholders of $46 million, primarily due to the 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.

2021 Compared to 2020

Net Income. CenterPoint Energy reported income available to common shareholders of $1,391 million for 2021 compared to a loss available to common shareholders of $949 million for 2020.

Income available to common shareholders increased $2,340 million primarily due to the following items:

•an increase in net income of $245 million for the Electric reportable segment, as further discussed below;

•an increase in net income of $125 million for the Natural Gas reportable segment, as further discussed below; and

•a decrease in income available to common shareholders of $104 million for Corporate and Other, primarily due to net gain of $97 million on Energy Transfer equity securities in 2021 discussed further in Note 11 to the consolidated financial statements, a $28 million pre-tax payment related to the impact of Board-implemented governance changes announced in July 2021, approximately $51 million unfavorable income tax impact primarily driven by CARES Act benefit in 2020, and approximately $33 million of CenterPoint Energy Inc. debt redemption charges in 2021; partially offset by approximately $15 million of lower interest expense as a result of the debt redemptions and a decrease in income allocated to preferred shareholders of $58 million due to the conversion of Series C Preferred Stock to Common Stock during 2020 and $22 million primarily due to the conversion of Series B Preferred Stock to Common Stock during 2021; and

•an increase in income of $2,074 million from discontinued operations, discussed further in Note 4 to the consolidated financial statements.

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

CENTERPOINT ENERGY’S RESULTS OF OPERATIONS BY REPORTABLE SEGMENT

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

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

ELECTRIC

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


	Year Ended December 31,									Favorable (Unfavorable)
	2022			2021			2020			2022 to 2021			2021 to 2020
	(in millions, except throughput, weather and customer data)
Revenues	$	4,108		$	3,763		$	3,470		$	345		$	293
Expenses:
Utility natural gas, fuel and purchased power	222			186			147			(36)			(39)
Operation and maintenance	1,864			1,761			1,683			(103)			(78)
Depreciation and amortization	793			775			684			(18)			(91)
Taxes other than income taxes	275			268			268			(7)			—
Goodwill Impairment (1)	—			—			185			—			185
Total expenses	3,154			2,990			2,967			(164)			(23)
Operating Income	954			773			503			181			270
Other Income (Expense):
Interest and other finance charges	(235)			(226)			(220)			(9)			(6)

Other income (expense), net	31			23			19			8			4
Income before income taxes	750			570			302			180			268
Income tax expense	147			95			72			(52)			(23)
Net income	$	603		$	475		$	230		$	128		$	245
Throughput (in GWh):
Residential	35,074			32,067			32,630			9		%	(2)		%
Total	105,541			103,000			98,647			2		%	4		%
Weather (percentage of normal weather for service area):
Cooling degree days	110		%	108		%	109		%	2		%	(1)		%
Heating degree days	121		%	82		%	76		%	39		%	6		%
Number of metered customers at end of period:
Residential	2,534,730			2,493,832			2,433,474			2		%	2		%
Total	2,858,203			2,814,859			2,749,116			2		%	2		%

(1)For information related to the 2020 goodwill impairment at the Indiana Electric reporting unit, see Note 6 to the consolidated financial statements.

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


	Favorable (Unfavorable)
	2022 to 2021		2021 to 2020
	(in millions)
Revenues
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 below	$	157	$	254
Weather, efficiency improvements and other usage impacts, excluding impact of COVID-19	54		(57)
Customer rates and impact of the change in rate design	38		(80)
Cost of fuel and purchased power, offset in utility natural gas, fuel and purchased power below	36		39
Refund of protected and unprotected EDIT, offset in income tax expense	32		(8)
Customer growth	28		32
Pass-through revenues, offset in operation and maintenance below	21		2
Miscellaneous revenues, primarily related to service connections and off-system sales	11		4
Equity return, related to the annual true-up of transition charges for amounts over or under collected in prior periods	2		9
Impacts from increased peak demand in the prior year, collected in rates in the current year	2		6
Impacts on usage from COVID-19	—		28
Energy efficiency, partially offset in operation and maintenance below	(3)		12
Bond Companies, offset in other line items below	(33)		52
Total	$	345	$	293
Utility natural gas, fuel and purchased power
Cost of purchased power, offset in revenues above	12		6
Cost of fuel, including coal, natural gas, and fuel oil, offset in revenues above	(48)		(45)
	$	(36)	$	(39)
Operation and maintenance
Transmission costs billed by transmission providers, offset in revenues above	$	(77)	$	(90)
All other operation and maintenance expense, including materials and supplies and insurance	(39)		(8)
Pass through expenses, offset in revenues above	(19)		(3)
Contract services	(2)		—
Merger related expenses, primarily severance and technology	—		10
Bond Companies, offset in other line items	3		(1)
Energy efficiency, offset in revenues above	4		(1)
Labor and benefits	7		9
Support services	20		6
Total	$	(103)	$	(78)
Depreciation and amortization
Bond Companies, offset in other line items	$	22	$	(58)
Ongoing additions to plant-in-service	(40)		(33)
Total	$	(18)	$	(91)
Taxes other than income taxes
Incremental capital projects placed in service	$	(14)	$	(2)
Franchise fees and other taxes	7		2
Total	$	(7)	$	—
Goodwill impairment
See Note 6 for further information	$	—	$	185
Total	$	—	$	185
Interest expense and other finance charges
Changes in outstanding debt	$	(32)	$	(19)
Other, primarily AFUDC and impacts of regulatory deferrals	15		6
Bond Companies, offset in other line items above	8		7
Total	$	(9)	$	(6)
Other income (expense), net
Reduction to non-service benefits costs	$	—	$	5
Other income, including AFUDC - equity	8		—

Investments in CenterPoint Energy Money Pool interest income	—		(1)
Total	$	8	$	4

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

NATURAL GAS

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


	Year Ended December 31,									Favorable (Unfavorable)
	2022			2021			2020			2022 to 2021			2021 to 2020
	(in millions, except throughput, weather and customer data)
Revenues	$	4,946		$	4,336		$	3,631		$	610		$	705
Expenses:
Utility natural gas, fuel and purchased power	2,665			1,941			1,341			(724)			(600)
Non-utility cost of revenues, including natural gas	4			18			17			14			(1)
Operation and maintenance	919			979			995			60			16
Depreciation and amortization	466			527			491			61			(36)
Taxes other than income taxes	261			253			237			(8)			(16)
Total expenses	4,315			3,718			3,081			(597)			(637)
Operating Income	631			618			550			13			68
Other Income (Expense)
Gain on sale	303			8			—			295			8
Interest expense and other finance charges	(137)			(141)			(153)			4			12

Other income (expense), net	(62)			(2)			6			(60)			(8)
Income from Continuing Operations Before Income Taxes	735			483			403			252			80
Income tax expense	243			80			125			(163)			45
Net Income	$	492		$	403		$	278		$	89		$	125
Throughput (in Bcf):
Residential	240			241			237			—		%	2		%
Commercial and industrial	424			428			439			(1)		%	(3)		%
Total Throughput	664			669			676			(1)		%	(1)		%
Weather (percentage of 10-year average for service area):
Heating degree days	106		%	91		%	91		%	15		%	—		%
Number of customers at end of period:
Residential	3,964,221			4,372,428			4,328,607			(9)		%	1		%
Commercial and industrial	301,834			354,602			349,725			(15)		%	1		%
Total	4,266,055			4,727,030			4,678,332			(10)		%	1		%

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


	Favorable (Unfavorable)
	2022 to 2021		2021 to 2020
	(in millions)
Revenues
Cost of natural gas, offset in utility natural gas, fuel and purchased power below	$	923	$	600
Customer rates and impact of the change in rate design, exclusive of the TCJA impact below	69		65
Non-volumetric and miscellaneous revenue, excluding impacts from COVID-19	26		(16)
Weather and usage, excluding impacts from COVID-19	22		12
Gross receipts tax, offset in taxes other than income taxes below	19		13
Customer growth	16		13
Refund of protected and unprotected EDIT, offset in income tax expense	6		(8)
Energy efficiency, offset in operation and maintenance below	3		(7)
Impacts of COVID-19, including usage and other miscellaneous charges	—		16
Changes in non-utility revenues, including impacts of MES disposal	(17)		17
Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale	(457)		—
Total	$	610	$	705
Utility natural gas, fuel and purchased power
Cost of natural gas, offset in revenues above	(923)		$	(600)
Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale	199		—
	$	(724)	$	(600)
Non-utility costs of revenues, including natural gas
Non-utility cost of revenues, including natural gas	14		(1)
	$	14	$	(1)
Operation and maintenance
Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale	$	125	$	—
Contract services	(14)		(3)
Merger related expenses, primarily severance and technology	—		8
Energy efficiency, offset in revenues above	(3)		7
Corporate support services	(22)		(8)
Labor and benefits, primarily due to headcount	(5)		(19)
Miscellaneous operations and maintenance expenses, including bad debt expense	(21)		31
Total	$	60	$	16
Depreciation and amortization
Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale	$	66	$	—
Lower depreciation rates in Indiana from 2021 rate order	18		—
Incremental capital projects placed in service	(23)		(36)
Total	$	61	$	(36)
Taxes other than income taxes
Gross receipts tax, offset in revenues above	$	(19)	$	(13)
Incremental capital projects placed in service	(12)		(3)
Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale	23		—
Total	$	(8)	$	(16)
Gain on Sale
Net gain on sale of MES	$	—	$	8
Gain on Sale of Arkansas and Oklahoma Natural Gas businesses	295		—
Total	$	295	$	8
Interest expense and other finance charges
Changes in outstanding debt	$	(11)	$	(2)
Other, primarily AFUDC and impacts of regulatory deferrals	15		14

Total	$	4	$	12


	Favorable (Unfavorable)
	2022 to 2021		2021 to 2020
	(in millions)
Other income (expense), net
Increase to non-service benefit cost, primarily settlement cost incurred in 2022	$	(66)	$	(10)
AFUDC - Equity, primarily from increased capital spend	3		—
Money pool investments with CenterPoint Energy interest income	—		2
Other miscellaneous non-operating income (expenses)	3		—
Total	$	(60)	$	(8)

Income Tax Expense. For a discussion of effective tax rate per period by Registrant, see Note 14 to the consolidated 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 Houston Electric’s ability to recover its regulatory assets. For information regarding factors that may affect the future results of Houston Electric’s consolidated operations, please read “Risk Factors” in Item 1A of Part I of this report.


	Year Ended December 31,									Favorable (Unfavorable)
	2022			2021			2020			2022 to 2021			2021 to 2020
	(in millions, except throughput, weather and customer data)
Revenues:
TDU	$	3,205		$	2,894		$	2,723		$	311		$	171
Bond Companies	207			240			188			(33)			52
Total revenues	3,412			3,134			2,911			278			223
Expenses:
Operation and maintenance, excluding Bond Companies	1,647			1,591			1,517			(56)			(74)
Depreciation and amortization, excluding Bond Companies	479			429			405			(50)			(24)
Taxes other than income taxes	261			251			252			(10)			1
Bond Companies	194			219			161			25			(58)
Total	2,581			2,490			2,335			(91)			(155)
Operating Income	831			644			576			187			68
Interest expense and other finance charges	(202)			(183)			(171)			(19)			(12)
Interest expense on Securitization Bonds	(13)			(21)			(28)			8			7
Other income, net	19			17			10			2			7
Income before income taxes	635			457			387			178			70
Income tax expense	125			76			53			(49)			(23)
Net income	$	510		$	381		$	334		$	129		$	47
Throughput (in GWh):
Residential	33,676			30,650			31,244			10		%	(2)		%
Total	100,062			96,898			93,768			3		%	3		%
Weather (percentage of 10-year average for service area):
Cooling degree days	110		%	109		%	110		%	1		%	(1)		%
Heating degree days	120		%	80		%	72		%	40		%	8		%
Number of metered customers at end of period:
Residential	2,402,329			2,359,168			2,303,315			2		%	2		%
Total	2,706,598			2,660,938			2,599,827			2		%	2		%

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


	Favorable (Unfavorable)
	2022 to 2021		2021 to 2020
	(in millions)
Revenues
Transmission Revenues, including TCOS and TCRF and impact of the change in rate design, inclusive of costs billed by transmission providers	$	157	$	254
Weather impacts and other usage	60		(51)
Refund of protected and unprotected EDIT, offset in income tax expense	32		(8)
Customer rates and impact of the change in rate design	30		(100)
Customer growth	27		31
Miscellaneous revenues	5		(1)
Impacts from increased peak demand in the prior year, collected in rates in the current year	2		6
Equity return, related to the annual true-up of transition charges for amounts over or under collected in prior periods	1		9
Impacts on usage from COVID-19	—		19
Energy efficiency, partially offset in operation and maintenance below	(3)		12
Bond Companies, offset in other line items below	(33)		52
Total	$	278	$	223
Operation and maintenance, excluding Bond Companies
Transmission costs billed by transmission providers, offset in revenues above	$	(77)	$	(90)
All other operation and maintenance expense, including materials and supplies and insurance	(21)		(2)
Merger related expenses, primarily severance and technology	—		9
Contract services	3		(3)
Energy efficiency program costs, offset in revenues above	3		(1)
Labor and benefits	12		11
Support services	24		2


Total	$	(56)	$	(74)
Depreciation and amortization, excluding Bond Companies
Ongoing additions to plant-in-service	$	(50)	$	(24)

Total	$	(50)	$	(24)
Taxes other than income taxes
Franchise fees and other taxes	$	4	$	4
Incremental capital projects placed in service	(14)		(3)
Total	$	(10)	$	1
Bond Companies expense
Operations and maintenance and depreciation expense, offset by revenues above	$	25	$	(58)
Total	$	25	$	(58)
Interest expense and other finance charges
Changes in outstanding debt	$	(32)	$	(19)

Other, primarily AFUDC and impacts of regulatory deferrals	13		7
Total	$	(19)	$	(12)
Interest expense on Securitization Bonds
Lower outstanding principal balance, offset by revenues above	$	8	$	7
Total	$	8	$	7
Other income (expense), net
Reduction to non-service benefit cost	$	—	$	8

Other income, including AFUDC - equity	2		—
Investments in CenterPoint Energy Money Pool interest income	—		(1)
Total	$	2	$	7

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

CERC CONSOLIDATED RESULTS OF OPERATIONS

CERC’s CODM views net income as the measure of profit or loss for its 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 and price movements of energy commodities as well as natural gas basis differentials. Our~~gas. CERC’s results of operations are also affected by, among other things, the actions of various federal, state and ~~state~~local governmental authorities having jurisdiction over rates ~~we charge, competition in our various business operations,~~CERC charges, debt service costs and income tax ~~expense.~~

~~The following table sets forth selected financial data for~~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 ~~years ended~~ ~~December 31, 2017~~, ~~2016~~ ~~and 2015, followed by a discussion of our consolidated~~future results of CERC’s consolidated operations, ~~based~~please read “Risk Factors” in Item 1A of Part I of this report.

CenterPoint Energy completed the Restructuring on ~~operating income. We have provided~~June 30, 2022, whereby the equity interests in Indiana Gas and VEDO, both subsidiaries it acquired in its acquisition of Vectren on February 1, 2019, were transferred from VUH to CERC Corp. As a ~~reconciliation~~result, Indiana Gas and VEDO became wholly owned subsidiaries of ~~consolidated operating income~~CERC Corp. The Restructuring was a non-cash common control acquisition by CERC. As a result, CERC acquired these businesses at CenterPoint Energy’s historical basis in these entities and prior year amounts were recast to ~~net income below.~~reflect the Restructuring as if it occurred at the earliest period presented for which CenterPoint Energy had common control.


	Year Ended December 31,									Favorable (Unfavorable)
	2022			2021			2020			2022 to 2021			2021 to 2020
	(in millions, except throughput, weather and customer data)
Revenues:	4,800			4,200			3,531			600			669
Expenses:
Utility natural gas, fuel and purchased power	2,607			1,885			1,313			(722)			(572)
Non-utility cost of revenues, including natural gas	4			17			17			13			—
Operation and maintenance	886			973			997			87			24
Depreciation and amortization	448			483			441			35			(42)
Taxes other than income taxes	257			249			234			(8)			(15)
Total expenses	4,202			3,607			3,002			(595)			(605)
Operating Income	598			593			529			5			64
Other Income (Expense)
Gain on sale	557			11			—			546			11
Interest expense and other finance charges	(130)			(134)			(143)			4			9

Other income (expense), net	(64)			(4)			(4)			(60)			—
Income from Continuing Operations Before Income Taxes	961			466			382			495			84
Income tax expense (benefit)	236			76			117			(160)			41
Income From Continuing Operations	725			390			265			335			125
Loss from Discontinued Operations (net of tax benefit of $—, $—, and $(2), respectively)	—			—			(66)			—			66
Net Income	$	725		$	390		$	199		$	335		$	191
Throughput (in BCF):
Residential	233			235			231			(1)		%	2		%
Commercial and industrial	389			396			410			(2)		%	(3)		%
Total Throughput	622			631			641			(1)		%	(2)		%
Weather (percentage of 10-year average for service area):
Heating degree days	106		%	91		%	91		%	15		%	—		%
Number of customers at end of period:
Residential	3,859,726			4,268,385			4,225,047			(10)		%	1		%
Commercial and industrial	291,184			336,828			332,210			(14)		%	1		%
Total	4,150,910			4,605,213			4,557,257			(10)		%	1		%

Year Ended December 31,
2017 2016 2015
(in millions)
Revenues $ 6,603
$ 4,454
$ 4,527
Expenses:

Natural gas 4,894
2,966
3,102
Operation and maintenance 839
777
741
Depreciation and amortization 279
249
227
Taxes other than income taxes 147
144
144
Total 6,159
4,136
4,214
Operating Income 444
318
313
Interest and other finance charges (123 ) (122 ) (137 )
Equity in earnings (losses) of unconsolidated affiliates 265
208
(1,633 )
Other income (loss), net (2 ) 3
6
Income (Loss) Before Income Taxes 584
407
(1,451 )
Income Tax Expense (Benefit) (161 ) 162
(539 )
Net Income (Loss) $ 745
$ 245
$ (912 )

~~2017 Compared~~Discontinued Operations. On February 24, 2020, CenterPoint Energy, through its subsidiary CERC Corp., entered into the Equity Purchase Agreement to ~~2016~~

~~Net Income.~~ Wesell the Energy Services Disposal Group. Accordingly, the previously reported ~~net income of $745 million for 2017 compared to net income of $245 million for 2016.~~

Energy Services reportable segment has been eliminated. The ~~increase in net income of $500 million was primarily due~~transaction closed on June 1, 2020. For further information, see Note 4 to the ~~following key factors:~~

a $323 million decrease in income tax expense, resulting from a reduction in income tax expense of $396 million due to tax reform, discussed further in Note 13 to our consolidated financial statements, offset by a $73 million increase in income tax expense primarily due to higher net income year over year;

~~a $126 million increase in operating income discussed below by segment; and~~

~~a $57 million increase in equity earnings from our investment in Enable, discussed further in Note 11 to our~~ consolidated financial statements.

~~These increases were partially offset by:~~

~~a $5 million decrease in miscellaneous other non-operating income included in Other Income, net shown above; and~~

a $1 million increase in interest expense due to the issuance of $300 million of unsecured senior notes and higher weighted average commercial paper interest rates discussed further in Note 12 to our consolidated financial statements.

~~Income Tax Expense.~~ We reported an effective tax rate of (28%) and 40% for the years ended December 31, 2017 and 2016, respectively. The effective tax rate of (28%) is primarily due 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 13 for a more in-depth discussion of the 2017 impacts of the TCJA.

~~2016 Compared to 2015~~

~~Net Income.~~ ~~We reported net income of $245 million for 2016 compared to a net loss of $912 million for 2015.~~

~~The increase in net income of $1,157 million was due 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 11 to our consolidated financial statements;

~~a $15 million decrease in interest expense due to lower weighted average interest rates on outstanding debt; and~~

~~a $5 million increase in operating income discussed below by segment.~~

~~These increases were partially offset by:~~

~~a $701 million increase in income tax expense due to higher income before tax; and~~

~~$3 million decrease in interest income included in Other income, net shown above.~~

~~Income Tax Expense.~~ We reported an effective tax rate of 40% and 37% for the years ended December 31, 2016 and 2015, respectively. The higher effective tax rate of 40% is due to a Louisiana state tax law change in the second quarter of 2016 resulting in an increase to our deferred tax liability.

~~RESULTS OF OPERATIONS BY BUSINESS SEGMENT~~

The following table presents operating income (loss) 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 (Loss) by Business Segment~~

Year Ended December 31,
2017 2016 2015
(in millions)
Natural Gas Distribution $ 328
$ 303
$ 273
Energy Services 125
20
42
Other Operations (9 ) (5 ) (2 )
Total Consolidated Operating Income $ 444
$ 318
$ 313

~~Natural Gas Distribution~~

The following table provides ~~summary data of our~~variance explanations by major income statement caption for CERC’s Natural Gas ~~Distribution business segment for 2017, 2016 and 2015:~~reportable segment:


	Favorable (Unfavorable)
	2022 to 2021			2021 to 2020
	(in millions)
Revenues
Cost of natural gas, offset in utility natural gas, fuel and purchased power below	$	921		$	572
Customer rates and impact of the change in rate design, exclusive of the TCJA impact	56			56
Non-volumetric and miscellaneous revenue	26			(16)
Weather and usage	22			11
Gross receipts tax, offset in taxes other than income taxes	19			13
Customer growth	16			12
Energy efficiency, offset in operation and maintenance	8			(4)
Refund of protected and unprotected EDIT, offset in income tax expense	6			(8)

Impacts of COVID-19	—			16
Changes in non-utility revenues, including impacts of MES disposal	(17)			17
Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale	(457)			—
Total	$	600		$	669
Utility natural gas, fuel and purchased power
Cost of natural gas, offset in revenues above	$	(921)		$	(572)
Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale	199			—
Total	$	(722)		$	(572)
Non-utility costs of revenues, including natural gas
Other, primarily non-utility cost of revenues	$	13		$	—
Total	$	13		$	—
Operation and maintenance
Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale	$	125		$	—
Contract services	(8)			(2)
Labor and benefits	(4)			(18)
Energy efficiency, offset in revenues above	(8)			4
Corporate Support Services	2			5
Merger related expenses, primarily severance and technology	—			8
Miscellaneous operations and maintenance expenses, including bad debt expense	(20)			27
Total	$	87		$	24
Depreciation and amortization			Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale
Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale	$	66		$	—
Indiana lower depreciation rates from recent rate order	13			—
Incremental capital projects placed in service	(44)			(42)


Total	$	35		$	(42)
Taxes other than income taxes
Gross receipts tax, offset in revenues	$	(19)		$	(13)
Incremental capital projects placed in service	(12)			(2)
Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale	23			—
Total	(8)			(15)
Gain on sale
Net gain on sale of Arkansas and Oklahoma Natural Gas businesses	$	546		$	—
Net gain on sale of MES	—			11
Total	$	546		$	11
Interest expense and other finance charges
Changes in outstanding debt	$	(11)		$	(5)
Other, primarily AFUDC and impacts of regulatory deferrals	15			14
Total	$	4		$	9

Year Ended December 31,
2017 2016 2015
(in millions, except throughput and customer data)
Revenues $ 2,639
$ 2,409
$ 2,632
Expenses:

Natural gas 1,164
1,008
1,297
Operation and maintenance 742
714
697
Depreciation and amortization 260
242
222
Taxes other than income taxes 145
142
143
Total expenses 2,311
2,106
2,359
Operating Income $ 328
$ 303
$ 273
Throughput (in Bcf):

Residential 151
152
171
Commercial and industrial 261
259
262
Total Throughput 412
411
433
Number of customers at end of period:

Residential 3,213,140
3,183,538
3,149,845
Commercial and industrial 256,651
255,806
253,921
Total 3,469,791
3,439,344
3,403,766


	Favorable (Unfavorable)
	2022 to 2021		2021 to 2020
	(in millions)
Other income (expense), net
Increase to non-service benefit cost	$	(65)	$	(10)
Other miscellaneous non-operating income (expenses)	—		10
Increase in Equity AFUDC	2		—
Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale	3		—
Total	$	(60)	$	—

~~2017 Compared to 2016.~~ ~~Our Natural Gas Distribution business segment reported operating income~~Income Tax Expense. For a discussion 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:~~

effective tax 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 our Energy Services business segment for 2017, 2016 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 gas 3,816
2,011
1,867
Operation and maintenance 87
59
42
Depreciation and amortization 19
7
5
Taxes other than income taxes 2
2
1
Total expenses 3,924
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 certain 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, expected to be substantially reversed in the first quarter of 2018 as natural gas prices normalize. Operating income in 2017 also included approximately $5 million of expenses relatedper period, see Note 14 to the ~~acquisition and integration of AEM. The remaining increase in operating income was primarily due to increased throughput related to the acquisition of AEM in 2017.~~consolidated financial statements.

~~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.

~~Midstream Investments~~

~~The following table summarizes the equity earnings (losses) of our Midstream Investments business segment for 2017, 2016 and 2015:~~

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.

~~Fluctuations in Commodity Prices and Derivative Instruments~~

For information regarding our exposure to risk as a result of fluctuations in commodity prices and derivative instruments, please read “Quantitative and Qualitative Disclosures About Market Risk” in Item 7A of this report.

LIQUIDITY AND CAPITAL RESOURCES

~~Our~~Historical Cash Flows

The net cash provided by (used in) operating, investing and financing activities for 2022, 2021 and 2020 is as follows:


	Year Ended December 31,
	2022						2021						2020
	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC
	(in millions)
Cash provided by (used in):
Operating activities	$	1,810	$	966	$	856	$	22	$	770	$	(1,219)	$	1,995	$	899	$	990
Investing activities	(1,628)		(2,435)		406		(1,851)		(1,617)		(1,287)		(1,265)		(564)		(770)
Financing activities	(345)		1,324		(1,277)		1,916		926		2,515		(834)		(416)		(223)

Operating Activities. The following items contributed to increased (decreased) net cash provided by operating activities:


	Year Ended December 31,
	2022 compared to 2021						2021 compared to 2020
	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC
	(in millions)
Changes in net income after adjusting for non-cash items	$	(492)	$	211	$	(169)	$	2,098	$	203	$	117
Changes in working capital	(615)		(177)		(107)		(155)		(101)		(236)
Increase in regulatory assets (1)	2,529		196		2,339		(2,188)		(226)		(2,017)
Change in equity in earnings of unconsolidated affiliates	339		—		—		(1,767)		—		—
Change in distributions from unconsolidated affiliates (2) (3)	(155)		—		—		42		—		—

Higher pension contribution	26		—		—		25		—		—
Other	156		(34)		12		(28)		(5)		(73)
	$	1,788	$	196	$	2,075	$	(1,973)	$	(129)	$	(2,209)

(1)The increase in regulatory assets is primarily due to 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.

(3)This change is partially offset by the change in distributions from Enable in excess of cumulative earnings in investing activities noted in the table below.

Investing Activities.The following items contributed to (increased) decreased net cash used in investing activities:


	Year Ended December 31,
	2022 compared to 2021						2021 compared to 2020
	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC
	(in millions)
Proceeds from the sale of equity securities	$	(618)	$	—	$	—	$	1,320	$	—	$	—



Net change in capital expenditures	(1,255)		(817)		(337)		(568)		(561)		(178)

Transaction costs related to the Enable Merger	49		—		—		(49)		—		—
Cash received related to Enable Merger	(5)		—		—		5		—		—
Net change in notes receivable from unconsolidated affiliates	—		—		—		—		(481)		9
Change in distributions from Enable in excess of cumulative earnings (1)	—		—		—		(80)		—		—
Proceeds from divestitures	2,053		—		2,053		(1,193)		—		(343)

Other	(1)		(1)		(23)		(21)		(11)		(5)
	$	223	$	(818)	$	1,693	$	(586)	$	(1,053)	$	(517)

(1)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.

Financing Activities.The following items contributed to (increased) decreased net cash used in financing activities:


	Year Ended December 31,
	2022 compared to 2021						2021 compared to 2020
	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC
	(in millions)
Net changes in commercial paper outstanding	$	(1,206)	$	—	$	(646)	$	1,893	$	—	$	582
Proceeds from issuances of preferred stock, net	—		—		—		(723)		—		—
Proceeds from issuance of Common Stock, net	—		—		—		(672)		—		—
Net changes in long-term debt outstanding, excluding commercial paper	(1,231)		386		(936)		2,450		415		1,481

Net changes in debt and equity issuance costs	2		(5)		(4)		(30)		(9)		(6)
Net changes in short-term borrowings	479		—		479		(27)		—		(27)

Decreased payment of Common Stock dividends	(55)		—		—		7		—		—
Decreased (increased) payment of Preferred Stock dividends	58		—		—		30		—		—
Payment of obligation for finance lease	(306)		(306)		—		(179)		(179)		—
Net change in notes payable from affiliated companies	—		(374)		(2,007)		—		496		508
Contribution from parent	—		1,013		149		—		68		(197)
Dividend to parent	—		(316)		(827)		—		551		111
Capital contribution to parent associated with the sale of CES	—		—		—		—		—		286
Other	(2)		—		—		1		—		—
	$	(2,261)	$	398	$	(3,792)	$	2,750	$	1,342	$	2,738

Future Sources and Uses of Cash

The Registrants expect that anticipated 2023 cash needs will be met with borrowings under their credit facilities, proceeds from the issuance of long-term debt (including ratepayer-backed securitization bonds), proceeds from the issuance by the Texas Public Financing Authority of customer rate relief bonds (which will not be a debt of CERC or its subsidiaries), term loans or common stock, 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 capital expenditures of approximately $655 million.~~

We expect that anticipated 2018 cash needs will be met with borrowings under our credit facility, proceeds from commercial paper, 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 debt securities in the capital markets or the arrangement of additional credit facilities. Issuances of debt in the capital markets, funds raised in the commercial paper markets, additional credit facilities and any sales of 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)
Natural Gas Distribution $ 523
$ 635
$ 612
$ 637
$ 664
$ 687
Energy Services 11
20
15
15
15
15
Total $ 534
$ 655
$ 627
$ 652
$ 679
$ 702

~~Our capital~~Capital expenditures are expected to be used for investment in infrastructure for ~~our~~electric and natural gas distribution operations. These capital expenditures are anticipated to maintain reliability and safety, ~~as well as~~increase resiliency and expand our systems through value-added projects. In addition to dividend payments on CenterPoint Energy’s Series A Preferred Stock and Common Stock, and in addition to interest payments on debt, the Registrants’ principal anticipated cash requirements for 2023 include the following:


	CenterPoint Energy		Houston Electric		CERC
	(in millions)
Estimated capital expenditures	$	3,639	$	1,815	$	1,427

Scheduled principal payments on Securitization Bonds	156		156		—

Maturing CERC senior notes and term loan	1,831		—		1,831

The following table sets forth the Registrants’ estimates of ~~our contractual~~the Registrants’ capital expenditures currently planned for projects for 2023 through 2027. See Note 17 to the consolidated financial statements for CenterPoint Energy’s actual capital expenditures by reportable segment for 2022.


	2023		2024		2025		2026		2027
CenterPoint Energy	(in millions)


Electric	$	2,102	$	3,335	$	2,251	$	2,246	$	2,388
Natural Gas	1,521		1,363		1,349		1,775		1,817
Corporate and Other	16		18		18		18		18

Total	$	3,639	$	4,716	$	3,618	$	4,039	$	4,223
Houston Electric (1)	$	1,815	$	1,970	$	1,863	$	2,098	$	2,246




CERC (1)	$	1,427	$	1,311	$	1,277	$	1,690	$	1,738

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

Capital Expenditures for Climate-Related Projects. On September 23, 2021, CenterPoint Energy announced a new 10-year capital expenditure plan. As part of its 10-year plan to spend over $40 billion on capital expenditures, CenterPoint Energy anticipates spending over $3 billion in clean energy investments and enablement, which may be used to support, among other things, renewable energy generation and electric vehicle expansion. CenterPoint Energy announced in November 2022 an increase of $2.3 billion to its 10-year capital plan, concluding in 2030, which now totals nearly $43 billion.

The following table summarizes the Registrants’ material current and long-term cash requirements as of December 31, 2022.


	Total		2023		2024-2025		2026-2027		2028 and thereafter
	(in millions)
CenterPoint Energy
Securitization Bonds	$	317	$	156	$	161	$	—	$	—
Other long-term debt (1)	16,021		1,335		1,273		3,761		9,652
Interest payments — Securitization Bonds (2)	12		8		4		—		—
Interest payments — other long-term debt (2)	8,049		651		1,196		1,133		5,069
Short-term borrowings	511		511		—		—		—





Commodity and other commitments (3)	7,152		1,165		2,424		1,040		2,523

Total cash requirements	$	32,062	$	3,826	$	5,058	$	5,934	$	17,244


	Total		2023		2024-2025		2026-2027		2028 and thereafter
	(in millions)
Houston Electric
Securitization Bonds	$	317	$	156	$	161	$	—	$	—
Other long-term debt (1)	6,036		—		—		600		5,436
Interest payments — Securitization Bonds (2)	12		8		4		—		—
Interest payments — other long-term debt (2)	4,693		235		467		456		3,535




Total cash requirements	$	11,058	$	399	$	632	$	1,056	$	8,971


CERC
Long-term debt	$	4,826	$	1,331	$	10	$	891	$	2,594
Interest payments — long-term debt (2)	1,897		195		327		313		1,062
Short-term borrowings	511		511		—		—		—



Commodity and other commitments (3)	5,096		894		1,426		822		1,954
Total cash requirements	$	12,330	$	2,931	$	1,763	$	2,026	$	5,610

(1)ZENS obligations ~~including~~are included in the 2028 and thereafter column at their contingent principal amount of $26 million as of December 31, 2022. 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 ($507 million as of December 31, 2022), as discussed in Note 11 to the consolidated financial statements.

(2)The Registrants calculated estimated interest payments ~~due by period (in millions):~~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, 2022. The Registrants typically expect to settle such interest payments with cash flows from operations and short-term borrowings.

(3)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)
Long-term debt $ 2,457
$ —
$ —
$ 1,491
$ 966
Interest payments — long-term debt (1)
1,455
98
196
144
1,017
Short-term borrowings 39
39
—
—
—
Operating leases (2)
23
5
7
6
5
Benefit obligations (3)
—
—
—
—
—
Non-trading derivative liabilities 24
20
4
—
—
Other commodity commitments (4)
1,221
463
522
128
108
Total contractual cash obligations (5)
$ 5,219
$ 625
$ 729
$ 1,769
$ 2,096


~~(1)~~	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.


~~(2)~~	~~For a discussion of operating leases, please read Note 14(c) to our consolidated financial statements.~~


~~(3)~~	We expect to contribute approximately $5 million to our postretirement benefits plan in 2018 to fund a portion of our obligations in accordance with rate orders or to fund pay-as-you-go costs associated with the plan.


~~(4)~~	~~For a discussion of other commodity commitments, please read Note 14(a) to our consolidated financial statements.~~


~~(5)~~	This table does not include estimated future payments for expected future AROs. These payments are primarily estimated to be incurred after 2023. We record a separate liability for the fair value of AROs, which totaled $243 million as of December 31, 2017. See Note 3(c) to our consolidated financial statements.

The table above does not include the following:

•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 2023. 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 ~~operating~~Houston 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

COVID-19 Regulatory Matters

For information about COVID-19 regulatory matters, see Note 7 to the consolidated financial statements.

February 2021 Winter Storm Event

For information about the February 2021 Winter Storm Event, see Note 7 to the consolidated financial statements, and for additional information on the Texas electric market, see “Risk Factors — Risk Factors Affecting Electric Generation, Transmission and Distribution Business — In connection with the February...”

Indiana Electric CPCN (CenterPoint Energy)

BTAs

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

On July 5, 2022, Indiana Electric entered into a BTA to acquire a 130 MW solar array in Pike County, Indiana through a special purpose entity for a capped purchase price. A CPCN for the project was filed with the IURC on July 29, 2022. On September 21, 2022, an agreement in principle was reached resolving all the issues between Indiana Electric and OUCC. The Stipulation and Settlement agreement was filed on October 6, 2022 and a settlement hearing was held on November 1, 2022. On January 11, 2023, the IURC issued an order approving the settlement agreement granting Indiana Electric to purchase and acquire the Pike County solar project through a BTA and approved the estimated cost. The IURC also designated the project as a clean energy project under Ind. Code Ch. 8-1-8.8, approved the proposed levelized rate and associated ratemaking and accounting treatment. The project is expected to be placed in service by the first quarter of 2025.

On January 10, 2023, Indiana Electric filed a CPCN with the IURC to acquire a wind energy generating facility 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. The construction phase is expected to commence during the second half of 2023 to achieve commercial operation by January 1, 2025. Indiana Electric has requested recovery via the CECA mechanism or through base rates in the next general rate case, depending on which provides more timely recovery. 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 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. The amended PPA will be brought before the IURC in a fully docketed proceeding in the second quarter of 2023. The Clenera solar array is expected to be placed in service in the second quarter of 2025.

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

Natural Gas Combustion Turbines

On June 17, 2021, Indiana Electric filed a CPCN with the IURC seeking approval to construct two natural gas combustion turbines to replace portions of its existing coal-fired generation fleet. On June 28, 2022, the IURC approved the CPCN. The estimated $334 million turbine facility is planned to be constructed at the current site of the A.B. Brown power plant in Posey County, Indiana and would provide a combined output of 460 MW. Indiana Electric received approval for depreciation expense and post in-service carrying costs to be deferred in a regulatory asset until the date Indiana South’s base rates include a return on and recovery of depreciation expense on the facility. A new approximately 23.5 mile pipeline will be constructed and operated by Texas Gas Transmission, LLC to supply natural gas to the turbine facility. FERC granted a certificate to construct the pipeline on October 20, 2022. The period to challenge FERC’s certificate in a federal district court expires on February 20, 2023. Indiana Electric granted its contractor a full notice to proceed to construct the turbines on December 9, 2022. The facility is targeted to be operational by year end 2025. Recovery of the proposed natural gas combustion turbines and regulatory asset will be requested in the next Indiana Electric rate case expected in 2023.

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, and it remains out of service. The current estimate of the costs to repair F.B. Culley Unit 3 is approximately $6 million to $7 million, which will largely be capital expenditures. CenterPoint Energy has located a replacement boiler feed pump turbine which is currently being refurbished by the original equipment manufacturer to ensure it is in good working order. Currently, F.B. Culley Unit 3 is expected to return to service in the first half of 2023 depending on the time it takes to refurbish, install and test operation of the replacement turbine and related materials. CenterPoint Energy is evaluating the applicability of insurance coverages. For the duration of the unplanned outage, CenterPoint Energy expects to meet its generation capacity needs from its other generation units and power purchase agreements.

Indiana Electric Securitization of Planned Generation Retirements (CenterPoint Energy)

The State of Indiana has enacted legislation, Senate Bill 386, that would enable CenterPoint Energy to request approval from the IURC to securitize the remaining book value and removal costs associated with certain generating facilities not more than twenty-four months before the unit is retired. The Governor of Indiana signed the legislation on April 19, 2021. On May 10, 2022, CenterPoint Energy (Indiana Electric) filed an application with the IURC to securitize qualified costs associated with its planned retirements of coal generation facilities. Total qualified costs are estimated at $359 million, of which $350 million would be financed and $9 million are estimated total ongoing costs. A hearing was held before the IURC on September 7, 2022 and a final order was received on January 4, 2023 authorizing the issuance of up to $350 million in securitization bonds. Per Senate Bill 386, CenterPoint Energy has 90 days after the 30-day appeal period has expired to issue the securitization bonds, subject to an approved extension.

Subsidiary Restructuring

In July 2021, Indiana North and SIGECO filed petitions with the IURC for the approval of a new financial services agreement and the confirmation of Indiana North’s financing authority, and final orders were issued by the IURC on December 28, 2021. VEDO filed a similar application with the PUCO in September 2021 and the PUCO issued an order on January 26, 2022 adopting recommendations by PUCO staff. Both the IURC and PUCO approved the petitions. The orders allowed the reissuance of existing debt of Indiana Gas and VEDO to CERC, the continued amortization of existing issuance expenses and discounts, and the treatment of any potential exchange fees as discounts to be amortized over the life of the debt. As a part of the Restructuring, on May 27, 2022, CERC Corp. and VUH completed an exchange with holders of VUH PPNs whereby CERC Corp. issued new senior notes with an aggregate principal amount of $302 million in return for all of their outstanding VUH PPNs with an aggregate principal amount of $302 million. Additionally, although not necessary to complete the Restructuring or the above mentioned exchange, on October 5, 2022, CERC Corp. closed a separate exchange offer of all outstanding VUH 6.10% senior notes for new notes of CERC Corp. For further information on the debt exchanges, see Note 13 to the consolidated financial statements. CenterPoint Energy completed the transfer of Indiana Gas and VEDO from VUH to CERC on June 30, 2022 to better align its organizational structure with management and financial reporting and to fund future capital investments more efficiently. See Note 1 to the consolidated financial statements for further information.

Bailey to Jones Creek Project (CenterPoint Energy and Houston Electric)

In April 2017, Houston Electric submitted a proposal to ERCOT requesting its endorsement of the Freeport Area Master Plan, which included the Bailey to Jones Creek Project. On November 21, 2019, the PUCT issued its final approval of Houston Electric’s certificate of convenience and necessity application, based on an unopposed settlement agreement under which Houston Electric would construct the project at an estimated cost of approximately $483 million. Houston Electric commenced pre-construction activities on the project in 2019, began construction in 2021, and completed construction and energized the line ahead of schedule in November 2021.Certain residual clean-up activities were done in 2022 and will continue in 2023.

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

On December 17, 2020, Houston Electric filed a certificate of convenience and necessity application with the PUCT for approval to build a 345 kV transmission line in Wharton County, Texas connecting the Hillje substation on Houston Electric’s transmission system to the planned 610 MW Space City Solar Generation facility being developed by third-party developer EDF Renewables. The actual capital costs of the project will depend on actual land acquisition costs, construction costs, and other factors. In November 2021, the PUCT approved a route that was estimated to cost $25 million and issued a final order on January 12, 2022. There have been project delays due to supply chain constraints in the developer acquiring solar panels. Houston Electric expects to complete construction and energization of the transmission line by the end of 2023.

Texas Legislation (CenterPoint Energy and Houston Electric)

Houston Electric continues to review the effects of legislation passed in 2021 and will be reviewing proposed bills that have been or will be submitted during the current 2023 legislative session for similar impacts where applicable. For example, pursuant to legislation passed in 2021, Houston Electric entered into two leases for TEEEF (mobile generation). Houston Electric sought initial recovery of the 2021 lease costs for the TEEEF and the operational costs for transportation, mobilization and demobilization, labor and materials for interconnections, fuel for commissioning, testing and operation, purchase and lease of auxiliary equipment, and labor and materials for operations in its 2022 DCRF application. Additionally, the 2021 legislation allows Houston Electric to seek recovery of transmission and distribution facilities that have a lead time of at least six months and would aid in restoring power to Houston Electric’s distribution customers following a widespread power outage.Houston Electric plans to seek recovery of costs associated with long-lead time facilities in a future DCRF or ratemaking proceeding. For further information regarding Houston Electric’s TEEEF, see Notes 7 and 20 to the consolidated financial statements.

Minnesota Base Rate Case (CenterPoint Energy and CERC)

On November 1, 2021, CERC filed a general rate case with the MPUC seeking approval for a revenue increase of approximately $67 million with a projected test year ended December 31, 2022. On September 23, 2022, the MPUC issued a written order approving the Settlement agreement which provides for a general revenue increase of $48.5 million and overall rate of return of 6.65%. The MPUC approved CERC’s compliance filing on January 17, 2023 and rate implementation began February 1, 2023. CERC plans to implement its Interim Rate Undercollection Plan in the second quarter of 2023 to collect the difference between authorized final rates and interim rates for the time period September 23, 2022 through January 31, 2023.

Minnesota Legislation (CenterPoint Energy and CERC)

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

•renewable natural gas (produces energy from organic materials such as wastewater, agricultural manure, food waste, agricultural or forest waste);

•renewable hydrogen gas (produces energy from water through electrolysis with renewable electricity such as solar);

•energy efficiency measures (avoids energy consumption in excess of the utility’s existing conservation programs); and

•innovative technologies (reduces or avoids greenhouse gas emissions using technologies such as carbon capture).

CERC expects to submit its first innovation plan to the MPUC in 2023. The maximum allowable cost for an innovation plan will start at 1.75% of the utility's revenue in the state and could increase to 4% by 2033, subject to review and approval by the MPUC.

Solar Panel Issues (CenterPoint Energy)

CenterPoint Energy’s current and future solar projects have been impacted by delays and/or increased costs. The potential delays and inflationary cost pressures communicated from the developers of our solar projects are primarily due to (i) unavailability of solar panels and other uncertainties related to the pending DOC investigation on anti-dumping and countervailing duties petition filed by a domestic solar manufacturer, (ii) the December 2021 Uyghur Forced Labor Prevention Act on solar modules and other products manufactured in China's Xinjiang Uyghur Autonomous Region and (iii) persistent general global supply chain and labor availability issues. On December 2, 2022, the DOC issued its preliminary determination, finding four of the eight companies being investigated are attempting to bypass U.S. duties; however, the investigation continues with the DOC’s final determination, which is currently scheduled for May 2023. In June 2022, President Biden authorized an executive order which would suspend anti-circumvention tariffs on solar panels for two years; however, the executive order could be subject to legal challenges and its effects remain uncertain. The resolution of these issues will determine what additional costs or delays our solar projects will be subject to. 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.

Rate Change Applications

WeThe 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. WeIn addition, Registrants are periodically involved in proceedings to adjust ~~our~~its capital tracking mechanisms ~~in Texas (GRIP)~~(e.g., ~~our~~CSIA, DCRF, DRR, GRIP, TCOS and TDSIC), its cost of service adjustments ~~in Arkansas, Louisiana, Mississippi~~(e.g., RSP and ~~Oklahoma (FRP, RSP, RRA and PBRC)~~RRA), ~~our~~its decoupling mechanism ~~in Minnesota,~~(e.g., Decoupling and ~~our~~SRC), and its energy efficiency cost trackers ~~in Arkansas,~~

~~Minnesota, Mississippi~~(e.g., CIP, DSMA, EECR, EECRF, EEFC and ~~Oklahoma (EECR, CIP, EECR and EECR)~~EEFR). The table below reflects significant applications pending or completed ~~during 2017.~~since the Registrants’ combined 2021 Form 10-K was filed with the SEC through February 15, 2023.

Mechanism

Annual Increase (Decrease) (1)

(in millions)

Filing
Date

Effective Date

Approval Date

Additional Information

CenterPoint Energy and Houston Electric (PUCT)

TCOS

September 2022

October 2022

Based on net change in invested capital of $317 million for the period January 1, 2022 through July 31, 2022.

EECRF

June
2022

March 2023

November 2022

The requested amount is comprised of the following: 2023 Program and Evaluation, Measurement and Verification costs of $38 million, a charge of $3 million related to the under-recovery of 2021 program costs including interest and rate case expenses, 2021 earned bonus of $23 million for a total of $64 million. On August 26, 2022, a unanimous settlement was filed for an adjusted total of $63 million comprised of the following: 2023 Program and Evaluation, Measurement and Verification costs of $37 million, a charge of $3 million related to the under-recovery of 2021 program costs including interest and rate case expenses, and a 2021 earned bonus of $23 million.

DCRF (1)

142

April
2022

TBD

As amended on July 1, 2022, the net change in distribution invested capital since its last base rate proceeding of over $1 billion for the period January 1, 2019 through December 31, 2021 for a revenue increase of $86 million, adjusted for load growth. In addition, the request includes approximately $200 million in TEEEF during the calendar year ending December 31, 2021 representing a revenue increase of $57 million. The requested overall revenue increase is $142 million with a proposed effective date of September 1, 2022. On July 11, 2022, a partial settlement was filed resolving the non-TEEEF issues. The settlement provides for a black box reduction to the revenue requirement of $7.8 million for a revenue increase of $78 million and a September 1, 2022 effective date for rates. A hearing on TEEEF issues was held on October 18 through 20, 2022. Briefs were filed on November 16, 2022 and reply briefs were filed on December 2, 2022. On January 27, 2023, the administrative law judges issued a proposal for decision recommending that the leasing of the TEEEF was not prudent or reasonable and necessary and that the PUCT deny recovery of all of the TEEEF costs. The PUCT is expected to consider the proposal for decision on March 9, 2023.

TCOS

February 2022

April
2022

April 2022

Based on net change of invested capital of $574 million.

Mechanism

Annual Increase (Decrease) (1)

(in millions)

Filing
Date

Effective Date

Approval Date

Additional Information

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

GRIP

March 2022

June
2022

Based on net change in invested capital for calendar year 2021 of $213 million.

CenterPoint Energy and CERC - Louisiana (LPSC)

RSP (1)

September 2022

TBD

Based on ROE of 9.95% with 50 basis point (+/-) earnings band. The North Louisiana increase, net of TCJA effects considered outside of the earnings band, is $3 million based on a test year ended June 2022 and adjusted ROE of 7.05%. The South Louisiana increase, net of TCJA effects considered outside of the earnings band, is $5 million based on a test year ended June 2022 and adjusted ROE of 4.19%. The TCJA refund impact to North Louisiana and South Louisiana was $1 million and $1 million, respectively. North Louisiana and South Louisiana also seek to recover regulatory assets due to COVID bad debt expenses in the amounts of $0.7 million and $0.3 million, respectively. Interim rates implemented on December 28, 2022, subject to refund.

CenterPoint Energy and CERC - Minnesota (MPUC)

CIP Financial Incentive

May 2022

October 2022

September 2022

The requested amount is attributed to the CIP Financial Incentive based on 2021 CIP program activity, and the approved Conservation Cost Recovery Adjustment charge is inclusive of the CIP Incentive as well as any over or under collections from CIP to reach a forecasted CIP tracker balance of zero.

Rate Case

November 2021

Feb 2023

September 2022

See discussion above under Minnesota Base Rate Case.

Decoupling

N/A

September 2021

April 2022

Represents under-recovery of approximately $19 million recorded for and during the period July 1, 2020 through June 30, 2021, including an approximately $5 million adjustment related to the implementation of final rates from the general rate case filed in 2019.

CenterPoint Energy and CERC - Mississippi (MPSC)

RRA

April
2022

August 2022

Based on ROE of 9.568% with 100 basis point (+/-) earnings band. Revenue increase of approximately $3 million based on 2021 test year adjusted earned ROE of 7.74%. Interim increase of approximately $1 million implemented May 31, 2022. A joint stipulation was filed on July 29, 2022 resolving all issues and an agreed revenue increase of $2 million based on 2021 test year adjusted earned ROE of 8.27% with rates effective in August 2022.

CenterPoint Energy - Indiana South - Gas (IURC)

CSIA

October 2022

January 2023

Requested an increase of $12 million to rate base, which reflects approximately $1 million annual increase in current revenues. 80% of revenue requirement is included in requested rate increase and 20% is deferred until the next rate case. The mechanism also includes a change in (over)/under-recovery variance of ($1 million) annually. Also included are unrecovered deferred O&M expenses of $9 million. OUCC filed on December 2, 2022 recommending approval of revenue requirement as filed, with additional recommendations on disallowing increases on cost estimates for a specific transmission project (no disallowances of actual costs in this filing). Rebuttal testimony was filed on December 9, 2022 responding to OUCC’s recommendations. A hearing was held on December 20, 2022, and an agreed upon joint proposed order was submitted to the judge on January 9, 2023, which the IURC approved on January 25, 2023.

CenterPoint Energy and CERC - Indiana North - Gas (IURC)

CSIA

October 2022

January 2023

Requested an increase of $38 million to rate base, which reflects a $3 million
annual increase in current revenues. 80% of revenue requirement is included in requested rate increase and 20% is deferred until the next rate case. The mechanism also includes a change in (over)/under-recovery variance of ($5 million) annually. Also included is unrecovered deferred operation and maintenance expenses of $20 million. OUCC filed on December 2, 2022 recommending changes to the Compliance Component Revenue Requirement as a result of recommending disallowance of actual costs for five distribution projects. Also recommended disallowing increases on cost estimates for certain projects. Rebuttal testimony was filed on December 9, 2022 responding to OUCC’s recommendations. A hearing was held on December 20, 2022, and an agreed upon joint proposed order was submitted to the judge on January 9, 2023, which the IURC approved on January 25, 2023.

Mechanism

Annual Increase (Decrease) (1)

(in millions)

Filing
Date

Effective Date

Approval Date

Additional Information

CenterPoint Energy and CERC - Ohio (PUCO)

DRR

April
2022

September 2022

August 2022

Requested an increase of $63 million to rate base for investments made in 2021, which reflects a $9 million annual increase in current revenues. A change in (over)/under-recovery variance of $(4 million) annually is also included in rates. PUCO issued order in August 2022 and rates implemented in September 2022. Filed a separate request on September 14, 2022 to extend the DRR beyond 2023 for investment through December 31, 2026 (no impact to revenues). The Staff report was filed January 11, 2023 with two recommendations: 1) For the extension period, any unrecovered capital investment in excess of the annual rate caps continue to be deferred, however, CERC shall cease accruing additional carrying charges on the amounts in excess of the annual rate cap; 2) Staff agrees with CERC that this program should be completed following this 3-year extension and recommends to the PUCO that this extension be granted contingent upon the DRR program ending and exclusive of any incremental investment following the completion of the mileage, projects and costs CERC outlined in this application. Objections are due by February 10, 2023. After reviewing the Staff Report and any objections filed, the PUCO will determine whether a hearing is necessary.

CenterPoint Energy - Indiana Electric (IURC)

TDSIC (1)

February 2023

TBD

Requested an increase of $31 million to rate base, which reflects a $5 million annual increase in current revenues. 80% of the revenue requirement is included in requested rate increase and 20% is deferred until next rate case. The mechanism also includes a change in (over)/under-recovery variance and a tax reform credit for a total of ($1 million).

CECA (1)

—

February 2023

TBD

Requested an increase of less than $1 million to rate base, which reflects an annual increase of less than $1 million in current revenues. The mechanism also includes a change in (over)/under-recovery variance of less than ($1 million).

TDSIC

August 2022

November 2022

Requested an increase of $43 million to rate base, which reflects a $3 million annual increase in current revenues. 80% of the revenue requirement is included in requested rate increase and 20% is deferred until next rate case. The mechanism also includes a change in (over)/under-recovery variance of less than ($1 million).

ECA

May 2022

August 2022

Requested an increase of $21 million to rate base, which reflects a $9 million annual increase in current revenues. 80% of the revenue requirement is included in requested rate increase and 20% is deferred until next rate case. The mechanism also includes a change in (over)/under-recovery variance of ($3 million).

TDSIC

February 2022

May
2022

Requested an increase of $42 million to rate base, which reflects a $3 million annual increase in current revenues. 80% of the revenue requirement is included in requested rate increase and 20% is deferred until next rate case. The mechanism also includes a change in (over)/under-recovery variance of less than $1 million.

CECA

(2)

February 2022

June
2022

May
2022

Requested a decrease of less than $1 million to rate base, which reflects a $3 million annual decrease in current revenues. The mechanism also includes a change in (over)/under-recovery variance of less than $1 million. This mechanism includes a non-traditional rate making approach related to a 50 MW universal solar array placed in service in January 2021.

~~Mechanism~~

~~Annual Increase~~ ~~(1)~~

~~(in millions)~~

~~Filing~~

~~Date~~

~~Effective Date~~

~~Approval Date~~

~~Additional Information~~

~~South Texas and Beaumont/East Texas (Railroad Commission)~~

~~GRIP~~

~~$7.6~~

~~March~~

~~2017~~

~~July~~

~~2017~~

~~June~~

~~2017~~

~~Based on net change in invested capital of $46.5 million.~~

~~Rate Case~~

~~(South Texas only)~~

~~0.5~~

~~November 2017~~

~~TBD~~

~~Reflects a proposed 10.3% ROE on a 55% equity ratio for South Texas jurisdiction.~~

~~Houston and Texas Coast (Railroad Commission)~~

~~Rate Case~~

~~16.5~~

~~November 2016~~

~~May~~

~~2017~~

~~May~~

~~2017~~

~~The Railroad Commission approved a unanimous settlement agreement establishing parameters for future GRIP filings, including a 9.6% ROE on a 55.15% equity ratio.~~

~~Texarkana, Texas Service Area (Multiple City Jurisdictions)~~

~~Rate Case~~

~~1.1~~

~~July~~

~~2017~~

~~September~~

~~2017~~

~~August 2017~~

~~Approved rates are consistent with Arkansas rates approved in 2016.~~

~~Arkansas (APSC)~~

~~EECR (2)~~

~~0.5~~

~~May~~

~~2017~~

~~January 2018~~

~~September 2017~~

~~Recovers $11.0 million, including an incentive of $0.5 million based on 2016 program performance.~~

~~FRP~~

~~7.6~~

~~April~~
~~2017~~

~~October~~
~~2017~~

~~September 2017~~

~~Based on ROE of 9.5% as approved in the last rate case. Unanimous Settlement Agreement was filed in July 2017 for $7.6 million and was subsequently approved.~~

~~BDA~~

~~3.9~~

~~March~~

~~2017~~

~~June~~

~~2017~~

~~June~~

~~2017~~

~~For the evaluation period between January 2016 and August 2016. Amounts are recorded during the evaluation period.~~

~~BDA~~

~~16.5~~

~~December 2017~~

~~February~~

~~2018~~

~~January~~

~~2018~~

~~For the evaluation period between October 2016 and September 2017. Amounts are recorded during the evaluation period.~~

~~Minnesota (MPUC)~~

~~Rate Case~~

~~56.5~~

~~August 2017~~

~~TBD~~

Reflects a proposed 10.0% ROE on a 52.18% equity ratio. Includes a proposal to extend decoupling beyond current expiration date of June 2018. Interim rates reflecting an annual increase of $47.8 million were effective October 1, 2017.

~~CIP (2)~~

~~13.8~~

~~May~~

~~2017~~

~~August 2017~~

~~Annual reconciliation filing for program year 2016 and includes performance bonus of $13.8 million.~~

~~Decoupling~~

~~20.4~~

~~September 2017~~

~~September~~

~~2017~~

~~February 2018~~

Reflects revenue under recovery for the period July 1, 2016 through June 30, 2017 and $3.0 million related to the under recovery of prior period adjustment factor. $9.2 million and $11.2 million was recognized in 2016 and 2017, respectively.

~~Mississippi (MPSC)~~

~~RRA~~

~~2.3~~

~~May~~

~~2017~~

~~July~~

~~2017~~

~~July~~

~~2017~~

~~Authorized ROE of 9.59% and a capital structure of 50% debt and 50% equity.~~

~~Louisiana (LPSC)~~

~~RSP~~

~~1.0~~

~~September 2016~~

~~December 2016~~

~~April~~

~~2017~~

~~Authorized ROE of 9.95% and a capital structure of 48% debt and 52% equity.~~

~~RSP~~

~~3.0~~

~~September 2017~~

~~December 2017~~

~~January 2018~~

~~Authorized ROE of 9.95% and a capital structure of 48% debt and 52% equity.~~

~~Oklahoma (OCC)~~

~~EECR (2)~~

~~0.4~~

~~March~~

~~2017~~

~~November 2017~~

~~October 2017~~

~~Recovers $2.6 million, including an incentive of $0.4 million based on 2016 program performance.~~

~~PBRC~~

~~2.2~~

~~March~~

~~2017~~

~~November 2017~~

~~October 2017~~

~~Based on ROE of 10%.~~


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

~~(2)~~

~~Amounts are recorded when approved.~~

~~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 NGD, federal income~~

Inflation Reduction Act (IRA)

On August 16, 2022, the IRA was signed into law. The new law extends or creates tax-related energy incentives for solar, wind and alternative clean energy sources, implements, subject to certain exceptions, a 1% tax ~~expense~~on share repurchases after December 31, 2022, and implements a 15% corporate alternative minimum tax based on the AFSI of those corporations with an average AFSI of $1 billion over the most recent three-year period. The IRA did not have a material impact on the Registrants’ 2022 financial results and no material impact is ~~included in~~expected for 2023 financial results. Further guidance on the ~~rates approved by state commissions~~tax provisions of the IRA is expected and ~~local municipalities and charged by those utilities~~the Registrants continue to ~~consumers. As NGD has general rate cases and other periodic rate adjustments, we expect~~evaluate the ~~lower corporate tax expense resulting from~~IRA provisions for the TCJA, which includes determining the treatment of EDIT, to be incorporated — along with other increases and decreases in our revenue requirements — into 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.~~their future financial results.

~~PHMSA Matters~~

Greenhouse Gas Regulation and Compliance (CenterPoint Energy)

On ~~December 19, 2016, PHMSA~~August 3, 2015, the EPA released its CPP rule, which required a 32% reduction in carbon emissions from 2005 levels. The final rule was published in the Federal Register on October 23, 2015, and that action was immediately followed by litigation ultimately resulting in the U.S. Supreme Court staying implementation of the rule. On July 8, 2019, the EPA published the ACE rule, which (i) repealed the CPP rule; (ii) replaced the CPP rule with a program that requires states to implement a program of energy efficiency improvement targets for individual coal-fired electric generating units; and (iii) amended the implementing regulations for Section 111(d) of the Clean Air Act. On January 19, 2021, the majority of the ACE rule — including the CPP repeal, CPP replacement, and the timing-related portions of the Section 111(d) implementing rule — was struck down by the U.S. Court of Appeals for the D.C. Circuit and on October 29, 2021, the U.S. Supreme Court agreed to consider four petitions filed by various coal interests and a coalition of 19 states. On June 30, 2022, the U.S. Supreme Court ruled that the EPA exceeded its authority in promulgating the CPP. The EPA has announced it plans on issuing new greenhouse gas rules in the future.

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

Compliance costs and other effects associated with climate change, reductions in GHG emissions and obtaining renewable energy sources remain uncertain. Although the amount of compliance costs remains uncertain, any new regulation or legislation

relating to climate change will likely result in an increase in compliance costs. While the requirements of a federal or state rule 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’ services may increase as a result of customer changes in response to climate change. For example, as the utilization of electric vehicles increases, demand for electricity may increase, resulting in increased usage of CenterPoint Energy’s systems and services. Any negative opinions with respect to CenterPoint Energy’s environmental practices or its ability to meet the challenges posed by climate change formed by regulators, customers, investors, legislators or other stakeholders could harm its reputation.

To address these developments, CenterPoint Energy announced its net zero emissions goals for both Scope 1 and ~~assess~~certain Scope 2 emissions by 2035. Indiana Electric’s 2019/2020 IRP identified a preferred portfolio that retires 730 MW of coal-fired generation facilities and replaces these resources with a mix of generating resources composed primarily of renewables, including solar, wind, and solar with storage, supported by dispatchable natural gas combustion turbines including a pipeline to serve such natural gas generation. Indiana Electric continues to execute on its 2019/2020 IRP and has received initial approvals for 756 MWs of the ~~potential~~700-1,000 MWs identified within Indiana Electric’s 2019/2020 IRP. Additionally, as reflected in its 10-year capital plan announced in September 2021, CenterPoint Energy anticipates spending over $3 billion in clean energy investments and enablement, which may be used to support, among other things, renewable energy generation and electric vehicle expansion. CenterPoint Energy believes its planned investments in renewable energy generation and corresponding planned reduction in its GHG emissions as part of its net zero emissions goals support global efforts to reduce the impacts of climate change. 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 modifications~~our ability to ~~this rule.~~secure cost-efficient insurance.

Other Matters

Credit ~~Facility~~Facilities

~~Our~~The Registrants may draw on their respective revolving credit ~~facility may be drawn on~~facilities from time to time to provide funds used for general corporate and limited liability company purposes, including to backstop ~~our~~CenterPoint Energy’s and CERC’s commercial paper ~~program.~~programs. The facilities may also be utilized to obtain letters of credit. For further details related to ~~our~~the Registrants’ revolving credit facilities, please see Note 13 to the consolidated financial statements.

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

On December 6, 2022, CenterPoint Energy, Inc. and its wholly owned subsidiaries, Houston Electric and CERC, replaced their existing revolving credit facilities with three revolving credit facilities totaling $3.75 billion in aggregate commitments. In addition, SIGECO entered into a new revolving credit facility ~~and~~totaling an additional $250 million in aggregate commitments. The aggregate amount of commitments among the ~~2017 amendment, please see Note 12~~four credit facilities total $4.0 billion.

Based on the consolidated debt to ~~our consolidated financial statements.~~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 billion as of December 31, 2022.

As of February 9, ~~2018, we~~2023, the Registrants had the following revolving credit ~~facility:~~ facilities and utilization of such facilities:


			Amount Utilized as of February 9, 2023
Registrant	Size of Facility		Loans		Letters of Credit		Commercial Paper		Weighted Average Interest Rate	Termination Date
	(in millions)
CenterPoint Energy	$	2,400	$	—	$	11	$	1,759	4.86%	December 6, 2027
CenterPoint Energy (1)	250		—		—		—		—%	December 6, 2027
Houston Electric	300		—		—		—		—%	December 6, 2027
CERC	1,050		—		—		1,049		4.82%	December 6, 2027
Total	$	4,000	$	—	$	11	$	2,808

Execution Date
Size of
Facility

Amount
Utilized as of
February 9, 2018
Termination Date
(in millions)
March 3, 2016 $ 900
$ 899
(1) March 3, 2022


~~(1)~~	~~Represents outstanding commercial paper of $898 million and outstanding letters of credit of $1 million.~~

~~For further details related to our revolving~~(1)This credit facility ~~please see Note 12 to our consolidated financial statements.~~was issued by SIGECO.

Borrowings under each of the revolving credit ~~facility~~facilities are subject to customary terms and conditions. However, there is no requirement that ~~we make~~the borrower makes representations prior to ~~borrowings~~borrowing as to the absence of material adverse changes or litigation that could be expected to have a material adverse effect. Borrowings under each of the revolving credit ~~facility~~facilities are subject to acceleration upon the occurrence of events of default that we consider customary. The revolving credit ~~facility~~facilities also ~~provides~~provide for customary fees, including commitment fees, administrative agent fees, fees in respect of letters of credit and other fees. ~~The~~In each of the revolving credit facilities, the spread to ~~LIBOR~~SOFR and the commitment fees fluctuate based on ~~our~~the borrower’s credit rating. WeEach 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 ~~our~~the four revolving credit ~~facility.~~facilities.

~~Long-term~~ Debt Transactions

~~In 2017, we retired or redeemed a combined $550 million aggregate principal amount of unsecured senior notes. Additionally, we issued $300 million aggregate principal amount of unsecured senior notes.~~ For ~~further~~detailed information about ~~our 2017~~the Registrants’ debt ~~transactions,~~issuances in 2022, see Note 1213 to ~~our~~the consolidated financial statements.

Securities Registered with the SEC

On ~~January 31, 2017, we~~May 29, 2020, the Registrants filed a joint shelf registration statement with the SEC registering indeterminate principal amounts of Houston Electric’s general mortgage bonds, CERC Corp.’s senior debt securities and CenterPoint Energy’s senior debt securities and junior subordinated debt securities and an indeterminate ~~principal amount~~number of ~~our senior debt securities.~~shares of Common Stock, shares of preferred stock, depositary shares, as well as stock purchase contracts and equity units. The joint shelf registration statement will expire on ~~January 31, 2020.~~May 29, 2023. For information related to the Registrants’ debt and equity security issuances in 2022, see Notes 12 and 13 to the consolidated financial statements.

Temporary Investments

As of February 9, ~~2018, we~~2023, the Registrants had no ~~external~~ temporary investments.

Money Pool

WeThe Registrants participate in a money pool through which wethey and certain of ~~our affiliates~~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 byunder CenterPoint ~~Energy under its~~Energy’s revolving credit facility or the sale byof CenterPoint ~~Energy of its~~Energy’s commercial paper. AsThe net funding requirements of ~~February 9, 2018, we had~~the CERC money pool are expected to be met with borrowings under CERC’s revolving credit facility or the sale of ~~$430 million from the money pool.~~CERC’s commercial paper. The money pool may not provide sufficient funds to meet ~~our~~the Registrants’ cash needs.

The table below summarizes CenterPoint Energy money pool activity by Registrant as of February 9, 2023:


	Weighted Average Interest Rate	Houston Electric		CERC
		(in millions)
Money pool borrowings	4.91%	$	(292)	$	(32)

Impact on Liquidity of a Downgrade in Credit Ratings

The interest rate on borrowings under ~~our~~the Registrants’ credit ~~facility~~facilities is based on ~~our~~their respective credit ~~rating. On December 4, 2017, S&P revised its rating outlook on our senior debt to stable from positive and affirmed its~~ ratings. ~~On September 24, 2017, Fitch revised its rating outlook on our senior debt to positive from stable and affirmed its rating.~~

As of February 9, ~~2018,~~2023, Moody’s, S&P and Fitch had assigned the following credit ratings to ~~our~~ senior ~~unsecured debt:~~

debt of the Registrants:

~~Moody’s~~

Moody’s

S&P

Fitch

~~Rating~~Registrant

Borrower/Instrument

Rating

Outlook (1)

Rating

Outlook (2)

Rating

Outlook (3)

~~Baa2~~CenterPoint Energy

~~Stable~~CenterPoint Energy Senior Unsecured Debt

A-Baa2

Stable

BBB

~~Positive~~Stable

BBB

Stable

CenterPoint Energy

Vectren Corp. Issuer Rating

n/a

BBB+

Stable

n/a

CenterPoint Energy

SIGECO Senior Secured Debt

Stable

n/a

Houston Electric

Houston Electric Senior Secured Debt

Stable

CERC

CERC Corp. Senior Unsecured Debt

Stable

BBB+

Stable

A-

Stable

CERC

Indiana Gas Senior Unsecured Debt

n/a

BBB+

Stable

n/a


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


~~(2)~~	~~An S&P 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 ~~our~~the Registrants’ securities and may be revised or withdrawn at any time by the rating agency. Each rating should be evaluated independently of any other rating. Any future reduction or withdrawal of one or more of ~~our~~the Registrants’ credit ratings could have a material adverse impact on ~~our~~the Registrants’ ability to obtain short- and long-term financing, the cost of such financings and the execution of ~~our~~the Registrants’ commercial strategies.

A decline in credit ratings could increase borrowing costs under ~~our~~the Registrants’ revolving credit ~~facility.~~facilities. If ~~our~~the Registrants’ credit ratings had been downgraded one notch by ~~each of the three principal credit rating agencies~~S&P and Moody’s from the ratings that existed atas of December 31, ~~2017,~~2022, the impact on the borrowing costs under ~~our~~the four revolving credit ~~facility~~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 ~~our~~the Registrants’ ability to complete capital market transactions and to access the commercial paper market. Additionally, a decline in credit ratings could increase cash collateral requirements and reduce earnings of ~~our~~CenterPoint Energy’s and CERC’s Natural Gas ~~Distribution and Energy Services business~~reportable segments.

CES, our wholly-owned subsidiary 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 our credit ratings (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 ~~our~~the credit ratings of CERC Corp. decline below the applicable threshold levels, weCERC might need to provide cash or other collateral of as much as ~~$196~~$237 million as of December 31, ~~2017.~~2022. The amount of collateral will depend on seasonal variations in transportation levels.

ZENS and Securities Related to ZENS (CenterPoint Energy)

If CenterPoint Energy’s creditworthiness were to drop such that ZENS holders thought its liquidity was adversely affected or the market for the ZENS were to become illiquid, some ZENS holders might decide to exchange their ZENS for cash. Funds for the payment of cash upon exchange could be obtained from the sale of the shares of ZENS-Related Securities that CenterPoint Energy owns or from other sources. CenterPoint Energy owns shares of ZENS-Related Securities equal to approximately 100% of the reference shares used to calculate its obligation to the holders of the ZENS. ZENS exchanges result in a cash outflow because tax deferrals related to the ZENS and shares of ZENS-Related Securities would typically cease when ZENS are exchanged or otherwise retired and shares of ZENS-Related Securities are sold. The ultimate tax liability related to the ZENS and ZENS-Related Securities continues to increase by the amount of the tax benefit realized each year, and there could be a significant cash outflow when the taxes are paid as a result of the retirement or exchange of the ZENS. If all ZENS had been exchanged for cash on December 31, 2022, deferred taxes of approximately $665 million would have been payable in 2022. If all the ZENS-Related Securities had been sold on December 31, 2022, capital gains taxes of approximately $80 million would have been payable in 2022 based on 2022 tax rates in effect. For additional information about ZENS, see Note 11 to the consolidated financial statements.

Cross Defaults

Under each 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 their 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 ~~our~~its subsidiaries’ debt instruments or revolving credit ~~facility.~~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, CenterPoint Energy~~ As announced ~~that it was 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.~~September 2021, and updated in November 2022, CenterPoint Energy has determined that it will no longer pursue a spin option at this time. More recently, CenterPoint Energy announced that late-stage discussions with a third party regarding a transaction involving our investmentincreased its planned capital expenditures in ~~Enable had terminated because an agreement on mutually acceptable terms could not be reached. We~~its Electric and Natural Gas businesses to support rate base growth and may ~~reduce our ownership in Enable over time through~~explore asset sales, in addition to 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. There can be no assurances that we will engage in any specific action or that any sale transaction or anycompleted sale of ~~common units~~its Natural Gas businesses located in ~~the public equity markets will be completed,~~Arkansas and ~~we do not intend~~Oklahoma, as a means to ~~disclose~~efficiently finance a portion of such increased capital expenditures. For further developments unless and until CenterPoint Energy’s 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.information, see Note 4.

~~Enable Midstream Partners~~

We receive quarterly cash distributions from Enable on its common 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 11 and 17 to our consolidated financial statements.

Hedging of Interest Expense for Future Debt Issuances

~~During 2017, we entered~~From 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 9(a) to ~~our~~the consolidated financial statements.

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

~~We have historically entered into partial weather hedges~~Houston Electric’s receivables from the distribution of electricity are collected from REPs that supply the electricity Houston Electric distributes to their customers. Before conducting business, a REP must register with the PUCT and must meet certain financial qualifications. Nevertheless, adverse economic conditions, 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 ~~certain NGD jurisdictions~~Houston Electric’s services or could cause them to ~~mitigate~~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 ~~impact~~event of ~~fluctuations from normal weather. We remain exposed~~a REP’s default, Houston Electric’s tariff provides a number of remedies, including the option for Houston Electric to ~~some weather risk as a result~~request that the PUCT suspend or revoke the certification of the ~~partial hedges. For more information about our weather hedges, see Note 9(a)~~REP. Applicable regulatory provisions require that customers be shifted to ~~our consolidated financial statements.~~another REP or a provider of last resort if a REP cannot make timely payments. However, Houston Electric remains at risk for payments related to services provided prior to the shift to the replacement REP or the provider of last resort. If a REP were unable to meet its obligations, it could consider, among various options, restructuring under the bankruptcy laws, in which event such REP might seek to avoid honoring its obligations and claims might be made against Houston Electric involving payments it had received from such REP. If a REP were to file for bankruptcy, Houston Electric may not be successful in recovering accrued receivables owed by such REP that are unpaid as of the date the REP filed for bankruptcy. However, PUCT regulations authorize utilities, such as Houston Electric, to defer bad debts resulting from defaults by REPs for recovery in future rate cases, subject to a review of reasonableness and necessity.

Other Factors that Could Affect Cash Requirements

In addition to the above factors, ~~our~~the 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 ~~our~~CenterPoint 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 ~~our~~ credit ~~facility;~~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);

•the ability of ~~GenOn~~REPs, including REP affiliates of NRG and ~~its subsidiaries, currently the subject of bankruptcy proceedings,~~Vistra Energy Corp., to satisfy their ~~obligations in respect of GenOn’s indemnity~~ obligations to CenterPoint Energy and ~~its 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 and SIGECO are limited in the amount of mortgage bonds they can issue by the General Mortgage and SIGECO’s mortgage indenture, respectively. For information about the total debt to capitalization financial covenants in ~~our~~the Registrants’ and SIGECO’s revolving credit ~~facility,~~facilities, see Note 1213 to ~~our~~the consolidated financial statements.

~~Relationship with CenterPoint Energy~~

We are an indirect, wholly-owned subsidiary of CenterPoint Energy. As a result of this relationship, the financial condition and liquidity of our parent company could affect our access to capital, our credit standing and our financial condition.

CRITICAL ACCOUNTING POLICIES

A critical accounting policy is one that is both important to the presentation of ~~our~~the Registrants’ financial condition and results of operations and requires management to make difficult, subjective or complex accounting estimates. An accounting estimate is an approximation made by management of a financial statement element, item or account in the financial statements. Accounting estimates in ~~our~~the Registrants’ historical consolidated financial statements measure the effects of past business transactions or events, or the present status of an asset or liability. The accounting estimates described below require 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 ~~our~~their financial condition, results of operations or cash flows. The circumstances that make these judgments difficult, subjective and/or complex have to do with the need to make estimates about the effect of matters that are inherently uncertain. Estimates and assumptions about future events and their effects cannot be predicted with certainty. WeThe Registrants base ~~our~~their 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 ~~our~~the Registrants’ operating environment changes. ~~Our~~The Registrants’ significant accounting policies are discussed in Note 2 to ~~our~~the 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 ~~the~~CenterPoint Energy’s Board of ~~Directors of CenterPoint Energy.~~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. ~~Our~~CenterPoint Energy, for its Electric and Natural Gas ~~Distribution business segment applies~~reportable segments, Houston Electric and CERC apply this 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 example, during 2022, the MPUC disallowed recovery of approximately $36 million of jurisdictional gas costs incurred during the February 2021 Winter Storm Event and CERC’s regulatory asset balance was reduced when such amounts were no longer probable of recovery. For further detail on ~~our~~the Registrants’ regulatory assets and liabilities, see Note 67 to ~~our~~the consolidated financial statements.

Impairment of Long-Lived Assets, Including Identifiable Intangibles ~~Goodwill~~ and ~~Equity Method Investments~~Goodwill

WeThe Registrants review the carrying value of ~~our~~ long-lived assets, including identifiable intangibles ~~goodwill~~ and ~~equity method investments~~goodwill, whenever events or changes in circumstances indicate that such carrying values may not be recoverable, and at least annually, goodwill is tested for ~~goodwill~~impairment 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~~goodwill, 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. We~~The Registrants recorded no ~~goodwill impairments during 2017, 2016 and 2015. We did not record material~~ impairments to long-lived assets, including intangibles or goodwill during ~~2017, 2016~~2022 and ~~2015. We recorded impairments totaling $1,225 million~~2021. During 2020, CenterPoint Energy recognized goodwill impairment losses as discussed further in Notes 4 and 6 to ~~our equity method investment during 2015 and no impairment during 2017 and 2016. See Notes 10 and 11 to our~~the consolidated financial ~~statements for further discussion of the impairments recorded to our equity method investment in 2015.~~statements.

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 ~~the~~an asset, liability or business could be bought or sold in a current transaction between willing parties and may be estimated using a number of techniques, including quoted market prices 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 determination~~Fair 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 non-rate regulated businesses, such as for Energy Systems Group, requires the estimation of the appropriate company specific risk premiums for those non-rate regulated 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 2022 annual goodwill impairment test during the third quarter of 2022 and determined, based on an income approach or a weighted combination of income and market approaches, that no goodwill impairment charge was required for any reporting unit. The fair values of ~~our Natural Gas Distribution and Energy Services~~each reporting ~~units~~unit significantly exceeded the carrying ~~values.~~value of the reporting unit.

Although ~~there was not a~~no goodwill ~~asset~~ impairment ~~in our 2017~~resulted from the 2022 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 ~~our~~CenterPoint Energy’s market capitalization falls below book value for an extended period of ~~time. No impairment triggers were identified subsequent to our 2017 annual test.~~time, or events affecting a reporting unit such as a contemplated disposal of all or part of a reporting unit.

~~During~~Common control transactions (CenterPoint Energy and CERC)

When accounting for a transfer of net assets or exchange of equity interests between entities under common control, the ~~year ended December 31, 2015, we determined~~entity that ~~an other than temporary decrease~~receives the net assets or the equity interests shall initially recognize the assets and liabilities transferred at the date of transfer based on the ultimate parent company’s basis, which in the ~~value~~case of ~~our investment~~the Restructuring is CenterPoint Energy’s basis. CenterPoint Energy’s basis in ~~Enable~~net assets of an entity may differ from the historical net assets of that entity on a standalone basis, for example, because push-down accounting had ~~occurred. The impairment analysis compared~~not been applied on a standalone basis. Additionally, when the ~~estimated~~net assets transferred in a common-control transaction meet the definition of a business, the receiving entity will record an allocation of goodwill from the reporting unit based on the relative fair value of ~~our investment~~the businesses transferred within that reporting unit. As a result, on June 30, 2022, CERC received $972 million of goodwill from CenterPoint Energy’s Natural Gas reporting unit in ~~Enable~~connection with the Restructuring. CERC recast prior periods to reflect the Restructuring as if it occurred at the earliest period presented for which CenterPoint Energy had common control. The Restructuring did not impact CenterPoint Energy’s basis in any entity, its allocation of goodwill to its ~~carrying~~reporting units, or its segment presentation. Neither CenterPoint Energy nor CERC recognized any gains or losses in connection with the Restructuring. SIGECO was not acquired by CERC and remains a subsidiary of VUH.

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

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

The fair value of the ~~investment~~businesses within the Natural Gas reporting unit was ~~determined using multiple valuation methodologies under both~~estimated based on a weighted combination of income and market approaches, consistent with the ~~market and income approaches.~~

~~Key assumptions~~methodology used in the ~~market approach include~~2021 annual goodwill impairment test (the most recent ~~market transactions of comparable companies and EBITDA to total enterprise multiples for comparable companies. Due to volatility~~annual test completed at the time of the ~~quoted price~~transaction).

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 ~~Enable’s common units,~~Directors, as applicable, commits to a ~~volume weighted average price was used under~~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 ~~market approach to best approximate~~disposal group, at the lower of their carrying value or their estimated fair value atless cost to sell.If a disposal group reflects a component of a reporting unit and meets the ~~measurement date. Key assumptions in~~definition of a business, 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~~goodwill within that reporting unit is allocated to the ~~discount rate used to determine~~disposal group based on the ~~present~~relative fair value of the ~~estimated future cash flows.~~ 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 ~~weighing of~~disposal group that meets the ~~different approaches was utilized to determine the estimated fair value of our investment in Enable.~~

Asheld for sale criteria and also represents a result of the analysis, we recorded other than temporary impairments on our equity method investment in Enable of $1,225 million during the year ended December 31, 2015. We based our assumptions on projected financial information that we believe is reasonable; however, actual results may differ materially from those projections. It is reasonably possible that the estimate of the impairment of our equity method investment in Enable will change in the near term duestrategic shift to the ~~following: actual Enable cash distribution~~Registrant is ~~materially lower than expected, significant adverse changes in Enable’s operating environment, increase in~~also reflected as discontinued operations on the ~~discount rate,~~Statements of Consolidated Income, and ~~changes in other key assumptions which require judgment and~~prior periods are ~~forward looking in nature.~~recast to reflect the earnings or losses from such businesses as income from discontinued operations, net of tax.

For further information, see Note 4 to the consolidated financial statements.

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.~~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

CenterPoint Energy sponsors pension and other retirement plans in various forms covering all employees who meet eligibility requirements. CenterPoint Energy uses several statistical and other factors that attempt to anticipate future events in calculating the expense and liability related to its 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, CenterPoint 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 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(o)~~2(u) to ~~our~~the 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(a)~~8(b) to ~~our~~the consolidated financial statements, weCenterPoint Energy maintains non-contributory qualified defined benefit pension plans covering eligible employees. Employer contributions for the qualified plans 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 CenterPoint Energy’s pension plans, it reserves the right to change, modify or terminate the plan. CenterPoint Energy’s funding policy is to review amounts annually and contribute an amount at least equal to the minimum contribution required under ERISA.

Additionally, CenterPoint Energy maintains unfunded non-qualified benefit restoration plans that allows participants to receive the benefits to which they would have been entitled under the 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.

CenterPoint Energy’s funding requirements and employer contributions for the years ended December 31, 2022, 2021 and 2020 were as follows:


	Year Ended December 31,
	2022		2021		2020
CenterPoint Energy	(in millions)
Minimum funding requirements for qualified pension plans	$	—	$	—	$	76
Employer contributions to the qualified pension plans	27		53		76
Employer contributions to the non-qualified benefit restoration plans	8		8		10

Although CenterPoint Energy’s minimum contribution requirement to the qualified pension plans in 2023 is zero, it expects to make contributions aggregating up to $50 million. CenterPoint Energy expects to make contributions aggregating approximately $7 million to the non-qualified benefit restoration plans in 2023.

Changes in pension obligations and plan assets may not be immediately recognized as pension expense in 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, CenterPoint Energy is required to (a) recognize on its Consolidated Balance Sheet an asset for the plan’s over-funded status or a liability for the plan’s under-funded status, (b) measure a plan’s assets and obligations as of the end of the fiscal year and (c) recognize changes in the funded status of the 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 $1.6 billion and $2.3 billion as of December 31, 2022 and 2021, 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 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.

As of December 31, 2022, the projected benefit obligation exceeded the market value of plan assets of CenterPoint Energy’s pension plans by $341 million. Changes in interest rates or the market values of the securities held by the plan during a year could materially, positively or negatively, change the funded status and affect the level of pension expense and required contributions at the next remeasurement.

Houston Electric and CERC participate in CenterPoint Energy’s qualified and non-qualified pension plans covering substantially all employees. ~~We recorded~~Pension cost by Registrant were as follows:


	Year Ended December 31,
	2022						2021						2020
	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC
	(in millions)
Pension cost	$	172	$	59	$	88	$	69	$	34	$	24	$	49	$	19	$	19

The calculation of pension cost and related liabilities requires the use of ~~$35 million, $37 million~~assumptions. Changes in these assumptions can result in different expense and ~~$26 million for~~liability amounts, and future actual experience can differ from the ~~years ended~~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, 2016~~2022, CenterPoint Energy’s qualified pension plans had an expected long-term rate of return on plan assets of 6.50% rate, which is 1.50% higher than the 5.00% rate assumed as of December 31, 2021. The expected rate of return assumption was developed using the targeted asset allocation of our plans and ~~2015, respectively,~~the expected return for each asset class. CenterPoint Energy regularly reviews its actual asset allocation and periodically rebalances plan assets to reduce volatility and better match plan assets and liabilities.

As of December 31, 2022, the projected benefit obligation was calculated assuming a discount rate of 5.15%, which ~~$29 million, $28 million~~is 84% higher than the 2.80% discount rate assumed as of December 31, 2021 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 ~~$15 million impacted pre-tax earnings, respectively. Our~~the expected duration of pension obligations specific to the characteristics of CenterPoint Energy’s plans.

CenterPoint Energy’s actuarially determined pension and other postemployment ~~expense~~cost for ~~2017~~2022 and ~~2016~~2021 that is greater or less than the amounts being recovered through rates in ~~certain~~the majority of Texas jurisdictions is deferred as a regulatory asset or liability, respectively. ~~The expected pension~~Pension cost for ~~2018~~2023, including the nonqualified benefit restoration plan, is ~~$22~~estimated to be $54 million ~~of which we expect $23 million to impact pre-tax earnings after effecting such~~

before 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%~~5.15% as of December 31, ~~2017.~~ 2022. If the expected return assumption were lowered by 0.50% from 6.50% to 6.00%, 2023 pension cost would increase by approximately $6 million.

As of December 31, 2022, the pension plans projected benefit obligation, including the unfunded nonqualified pension plans, exceeded plan assets by $341 million. If the discount rate were lowered by 0.50% from 5.15% to 4.65%, the assumption change would increase CenterPoint Energy’s projected benefit obligation by approximately $68 million and decrease its 2023 pension cost by approximately $2 million. The expected reduction in pension cost 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 CenterPoint Energy’s Consolidated Balance Sheets by increasing the regulatory asset recorded as of December 31, 2022 by $59 million and would result in a charge to comprehensive income in 2022 of $7 million, net of 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 ~~our~~CenterPoint Energy’s future pension expense and liabilities. WeCenterPoint Energy cannot predict with certainty what these factors will be in the future.

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 ~~our~~the Registrants’ consolidated financial statements. Most of the revenues and income from ~~our~~the Registrants’ business activities are affected by market risks. Categories of market risk include exposure to commodity prices through non-trading activities, interest rates and ~~interest rates.~~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.

~~Commodity~~•Equity price risk results from exposures to changes in ~~spot~~ prices ~~forward prices and~~of individual equity securities (CenterPoint Energy).

•Commodity price risk results from exposures to 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, we~~2022, the Registrants had outstanding long-term debt and lease obligations and CenterPoint Energy had obligations under its ZENS that subject usthem to the risk of loss associated with movements in market interest rates.

~~Our~~CenterPoint Energy’s floating rate obligations aggregated ~~$1.5~~$4.5 billion and ~~$569 million at~~ $4.5 billion as of December 31, ~~2017~~2022 and ~~2016~~,2021, respectively. If the floating interest rates were to increase by 10% from December 31, ~~2017~~2022 rates, ~~our~~CenterPoint Energy’s combined interest expense would increase by ~~$2.6~~approximately $19 million annually. In 2023, SIGECO expects to remarket $186 million of tax-exempt debt at then market rates due to mandatory purchase or mandatory tender for purchase provisions. On September 1, 2023, CenterPoint Energy’s Series A Preferred Stock will convert from a fixed rate dividend rate to a floating rate per annum equal to three month U.S. dollar LIBOR (or alternative benchmark rate) plus 3.270%. For further information regarding CenterPoint Energy’s Series A Preferred Stock, see Note 12 to the consolidated financial statements. CenterPoint Energy has no floating rate notes maturing in 2023, other than the CERC floating rate notes discussed below.

Houston Electric did not have any floating rate obligations as of either December 31, 2022 or 2021.

CERC’s floating rate obligations aggregated $1.4 billion and $1.9 billion as of December 31, 2022 and 2021, respectively. If the floating interest rates were to increase by 10% from December 31, 2022 rates, CERC’s combined interest expense would increase by approximately $7 million annually. CERC has $575 million of floating rate notes maturing in 2023 that will be refinanced at current rates.

As of December 31, ~~2017~~2022 and ~~2016, we~~2021, CenterPoint Energy had outstanding fixed-rate debt (excluding indexed debt securities) aggregating ~~$1.6~~$12.5 billion and ~~$1.8~~$11.7 billion, respectively, in principal amount and having a fair value of ~~$1.8~~$11.1 billion and ~~$2.0~~$13.0 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. However, the fair value of these instruments would increase by

approximately $510 million if interest rates ~~(see Note 12~~were to ~~our consolidated financial statements).~~decline by 10% from their levels as of December 31, 2022. CenterPoint Energy has no fixed-rate senior notes maturing in 2023, other than the CERC senior notes discussed below.

As of December 31, 2022 and 2021, Houston Electric had outstanding fixed-rate debt aggregating $6.4 billion and $5.5 billion, respectively, in principal amount and having a fair value of approximately $5.6 billion and $6.3 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 ~~$77~~$315 million if interest rates were to decline by 10% from their levels as of December 31, 2022. Houston Electric has no fixed-rate general mortgage bonds maturing in 2023.

As of December 31, 2022 and 2021, CERC had outstanding fixed-rate debt aggregating $3.5 billion and $2.5 billion, respectively, in principal amount and having a fair value of $3.3 billion and $2.8 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 $126 million if interest rates were to decline by 10% from their levels at December 31, ~~2017.~~ 2022. CERC has $757 million of fixed-rate senior notes maturing in 2023 that will be refinanced at current rates.

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 the consolidated financial statements, the ZENS obligation is bifurcated into a debt component and a derivative component. The debt component of $7 million at December 31, 2022 was a fixed-rate obligation and, therefore, did not expose CenterPoint Energy to the risk of loss in earnings due to changes in market interest rates. However, the fair value of the debt component would increase by approximately $1 million if interest rates were to decline by 10% from levels at December 31, 2022. Changes in the fair value of the derivative component, a $578 million recorded liability at December 31, 2022, are recorded in CenterPoint Energy’s Statements of Consolidated Income and, therefore, it 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, 2022 levels, the fair value of the derivative component liability would decrease by approximately $1 million, which would be recorded as an unrealized gain in CenterPoint Energy’s Statements of Consolidated Income.

Equity Market Value Risk (CenterPoint Energy)

CenterPoint Energy is exposed to equity market value risk through its ownership of 10.2 million shares of AT&T Common, 0.9 million shares of Charter Common and 2.5 million shares of WBD Common, which CenterPoint Energy holds to facilitate its ability to meet its obligations under the ZENS. See Note 11 to the consolidated financial statements for a discussion of CenterPoint Energy’s ZENS obligation. Changes in the fair value of the ZENS-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, 2022 aggregate market value of these shares would result in a net loss of less than $1 million, which would be recorded as a loss on debt securities in CenterPoint 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 our~~CenterPoint 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 instruments~~during severe weather events such as ~~futures, forward contracts, swaps~~hurricanes, tornadoes and ~~options derive their value from underlying assets, indices, reference rates~~severe 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 combination~~defer 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 into~~However, CenterPoint Energy’s regulated operations in ~~our non-trading operations to manage and hedge certain exposures, such as~~Indiana 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 value~~for transactions involving purchases and sales of natural gas, ~~inventory, is described below. We measure this commodity risk~~coal 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 purposes~~arrangements with an original term of ~~this analysis, we estimate commodity price risk by applying a $0.50 change in the forward NYMEX price~~up to ~~our net open~~10 years. This authority has been utilized to secure fixed price ~~position (including forward fixed price physical contracts,~~ natural gas ~~inventory~~using both physical purchases and ~~fixed price~~ financial ~~contracts) at the end of each period.~~derivatives. As of December 31, ~~2017,~~2022, the recorded fair value of ~~our~~ non-trading energy ~~derivatives~~derivative assets was ~~a net asset of $111~~$11 million ~~(before collateral), all of~~for CenterPoint Energy’s utility natural gas operations in Indiana, which is ~~related to our Energy Services business segment. A $0.50 change~~offset 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 impact~~volumes 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 of~~unaccounted for natural gas ~~inventory.~~

~~Commodity price risk is not limited to changes in forward NYMEX prices. Variation of commodity pricing between~~and other natural gas-related expenses, also mitigate the ~~different indices used to mark to market portions of our~~effect natural gas ~~inventory (Gas Daily) and~~costs may have on CenterPoint Energy’s financial condition. In 2008, the ~~related fair value hedge (NYMEX) can result~~PUCO approved an exit of the merchant function in ~~volatility~~CenterPoint Energy’s Ohio natural gas service territory, allowing Ohio customers to ~~our net income. Over time, any gains or losses on the sale of storage~~purchase 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.

Item 8.Financial Statements and Supplementary Data

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the ~~Stockholder~~Shareholders and Board of Directors of

CenterPoint Energy, ~~Resources Corp.~~Inc.

~~Houston, Texas~~

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of CenterPoint Energy, ~~Resources Corp.~~Inc. and subsidiaries (the ~~“Company”, an indirect wholly owned subsidiary of CenterPoint Energy, Inc.~~"Company") as of December 31, ~~2017~~2022 and ~~2016,~~2021, the related statements of consolidated income, comprehensive income, ~~stockholder’s~~changes in equity, and cash flows, for each of the three years in the period ended December 31, ~~2017,~~2022, and the related notes (collectively referred to as the ~~“financial statements”~~"financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, ~~2017~~2022 and ~~2016,~~2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, ~~2017,~~2022, 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, 2022, 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 17, 2023, 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~~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 Notes 2, 4 and 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.

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 by 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 affected account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future 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 uncertainty of decisions by the Commissions included the following, among others:

•We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs incurred and deferred as regulatory assets, and (2) refunds or future reductions in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management’s controls over the initial recognition of amounts as regulatory assets or liabilities; and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.

•We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.

•We read relevant regulatory orders issued by the Commissions for the Company and other public utilities, regulatory statutes, interpretations, procedural memorandums, filings made by intervenors, and other publicly available information 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. We evaluated the external information and compared to management’s recorded regulatory asset and liability balances for completeness.

•For regulatory matters in process, we inspected the Company’s filings with the Commissions and the filings with the Commissions by intervenors that may impact the Company’s future rates, for any evidence that might contradict management’s assertions.

•We evaluated management’s assertion that no indicators of impairment were identified in connection with the Company's property, plant, and equipment. We inspected the capital projects budget and inquired of management to identify projects that are designed to replace assets that may be retired prior to the end of the useful life. We inspected minutes of the board of directors and regulatory orders and other filings with the Commissions to identify any evidence that may contradict management’s assertion regarding probability of a disallowance of long-lived assets.

•We evaluated regulatory filings for any evidence that intervenors are challenging full recovery of the cost of any capital projects and inquired of management to assess whether capitalized costs are probable of disallowance.

•We obtained an analysis from management and letters from internal and external legal counsel, as appropriate, regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities not yet addressed in a regulatory order to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

February 17, 2023

We have served as the Company’s auditor since 1932.

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED INCOME


	Year Ended December 31,
	2022		2021		2020
	(in millions, except per share amounts)
Revenues:
Utility revenues	$	9,018	$	8,042	$	7,049
Non-utility revenues	303		310		369
Total	9,321		8,352		7,418
Expenses:
Utility natural gas, fuel and purchased power	2,887		2,127		1,488
Non-utility cost of revenues, including natural gas	204		208		257
Operation and maintenance	2,833		2,810		2,744
Depreciation and amortization	1,288		1,316		1,189
Taxes other than income taxes	543		528		516
Goodwill impairment	—		—		185
Total	7,755		6,989		6,379
Operating Income	1,566		1,363		1,039
Other Income (Expense):
Gain (loss) on equity securities	(227)		(172)		49
Gain (loss) on indexed debt securities	325		50		(60)
Gain on sale	303		8		—
Interest expense and other finance charges	(511)		(508)		(501)
Interest expense on Securitization Bonds	(13)		(21)		(28)



Other income (expense), net	(26)		58		64
Total	(149)		(585)		(476)
Income from Continuing Operations Before Income Taxes	1,417		778		563
Income tax expense	360		110		80
Income from Continuing Operations	1,057		668		483
Income (Loss) from Discontinued Operations (net of tax expense (benefit) of $-0-, $201, and $(333), respectively)	—		818		(1,256)
Net Income (Loss)	1,057		1,486		(773)
Income allocated to preferred shareholders	49		95		176

Income (Loss) Available to Common Shareholders	$	1,008	$	1,391	$	(949)

Basic earnings per common share - continuing operations	$	1.60	$	0.97	$	0.58
Basic earnings (loss) per common share - discontinued operations	—		1.38		(2.37)
Basic Earnings (Loss) Per Common Share	$	1.60	$	2.35	$	(1.79)
Diluted earnings per common share - continuing operations	$	1.59	$	0.94	$	0.58
Diluted earnings (loss) per common share - discontinued operations	—		1.34		(2.37)
Diluted Earnings (Loss) Per Common Share	$	1.59	$	2.28	$	(1.79)

Weighted Average Common Shares Outstanding, Basic	629		593		531
Weighted Average Common Shares Outstanding, Diluted	632		610		531

See Combined Notes to Consolidated Financial Statements

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME


	Year Ended December 31,
	2022		2021		2020
	(in millions)
Net Income (Loss)	$	1,057	$	1,486	$	(773)
Other comprehensive income (loss):
Adjustment to pension and other postemployment plans (net of tax expense of $2, $7 and $-0-, respectively)	32		21		(5)

Reclassification of deferred loss from cash flow hedges realized in net income (net of tax expense of $-0-, $-0- and $-0-, respectively)	1		2		—
Reclassification of net deferred losses from cash flow hedges (net of tax expense of $-0-, $-0-, and $4, respectively)	—		—		15
Other comprehensive income (loss) from unconsolidated affiliates (net of tax of $-0-, $-0-, and $-0-, respectively)	—		3		(2)
Total	33		26		8
Comprehensive income (loss)	1,090		1,512		$	(765)
Income allocated to preferred shareholders	49		95		176
Comprehensive income (loss) available to common shareholders	$	1,041	$	1,417	$	(941)

See Combined Notes to Consolidated Financial Statements

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS


	December 31, 2022		December 31, 2021
	(in millions)
ASSETS
Current Assets:
Cash and cash equivalents ($75 and $92 related to VIEs, respectively)	$	74	$	230
Investment in equity securities	510		1,439

Accounts receivable ($22 and $29 related to VIEs, respectively), less allowance for credit losses of $38 and $44, respectively	889		690
Accrued unbilled revenues, less allowance for credit losses of $4 and $6, respectively	764		513

Natural gas and coal inventory	241		186
Materials and supplies	635		422
Non-trading derivative assets	10		9
Taxes receivable	20		1
Current assets held for sale	—		2,338
Regulatory assets	1,385		1,395
Prepaid expense and other current assets ($13 and $19 related to VIEs, respectively)	171		132
Total current assets	4,699		7,355
Property, Plant and Equipment, net	27,143		23,484
Other Assets:
Goodwill	4,294		4,294
Regulatory assets ($229 and $420 related to VIEs, respectively)	2,193		2,321

Non-trading derivative assets	2		5




Other non-current assets	215		220
Total other assets	6,704		6,840
Total Assets	$	38,546	$	37,679

See Combined Notes to Consolidated Financial Statements

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS, cont.


	December 31, 2022		December 31, 2021
	(in millions, except par value and shares)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities:
Short-term borrowings	$	511	$	7
Current portion of VIE Securitization Bonds long-term debt	156		220
Indexed debt, net	7		10
Current portion of other long-term debt	1,346		308
Indexed debt securities derivative	578		903
Accounts payable	1,352		1,196

Taxes accrued	298		378
Interest accrued	159		136
Dividends accrued	144		131
Customer deposits	110		111
Non-trading derivative liabilities	—		2

Current liabilities held for sale	—		562
Other	452		323
Total current liabilities	5,113		4,287
Other Liabilities:
Deferred income taxes, net	3,986		3,904
Non-trading derivative liabilities	—		12
Benefit obligations	547		511
Regulatory liabilities	3,245		3,153

Other	774		836
Total other liabilities	8,552		8,416
Long-term Debt, net:
VIE Securitization Bonds, net	161		317
Other long-term debt, net	14,675		15,241
Total long-term debt, net	14,836		15,558
Commitments and Contingencies (Note 15)
Temporary Equity (Note 12)	3		3
Shareholders’ Equity:
Cumulative preferred stock, $0.01 par value, 20,000,000 shares authorized, 800,000 shares and 800,000 shares outstanding, respectively, $800 and $800 liquidation preference, respectively (Note 12)	790		790
Common stock, $0.01 par value, 1,000,000,000 shares authorized, 629,535,631 shares and 628,923,534 shares outstanding, respectively	6		6
Additional paid-in capital	8,568		8,529
Retained earnings	709		154
Accumulated other comprehensive loss	(31)		(64)
Total shareholders’ equity	10,042		9,415
Total Liabilities and Shareholders’ Equity	$	38,546	$	37,679

See Combined Notes to Consolidated Financial Statements

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED CASH FLOWS


	Year Ended December 31,
	2022		2021		2020
	(in millions)
Cash Flows from Operating Activities:
Net income (loss)	$	1,057	$	1,486	$	(773)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	1,288		1,316		1,189



Deferred income taxes	20		213		(429)
Goodwill impairment and loss from reclassification to held for sale	—		—		175
Goodwill impairment	—		—		185

Gain on divestitures	(303)		(681)		—

Loss (gain) on equity securities	227		172		(49)
Loss (gain) on indexed debt securities	(325)		(50)		60

Equity in (earnings) losses of unconsolidated affiliates	—		(339)		1,428
Distributions from unconsolidated affiliates	—		155		113
Pension contributions	(35)		(61)		(86)
Changes in other assets and liabilities:
Accounts receivable and unbilled revenues, net	(461)		(98)		90

Inventory	(259)		(140)		9
Taxes receivable	(19)		81		24
Accounts payable	203		175		2

Net regulatory assets and liabilities	234		(2,295)		(107)
Other current assets and liabilities	(5)		56		104
Other non-current assets and liabilities	109		(53)		25
Other operating activities, net	79		85		35
Net cash provided by operating activities	1,810		22		1,995
Cash Flows from Investing Activities:
Capital expenditures	(4,419)		(3,164)		(2,596)


Transaction costs related to Enable Merger (Note 4)	—		(49)		—
Cash received related to Enable Merger	—		5		—
Distributions from unconsolidated affiliates in excess of cumulative earnings	—		—		80



Proceeds from sale of equity securities, net of transaction costs	702		1,320		—
Proceeds from divestitures (Note 4)	2,075		22		1,215


Other investing activities, net	14		15		36
Net cash used in investing activities	(1,628)		(1,851)		(1,265)
Cash Flows from Financing Activities:
Increase (decrease) in short-term borrowings, net	452		(27)		—
Payment of obligation for finance lease	(485)		(179)		—
Borrowings from revolving credit facilities	—		—		1,050
Repayments of revolving credit facilities	—		—		(1,050)
Proceeds from (payments of) commercial paper, net	(74)		1,132		(761)
Proceeds from long-term debt	2,089		4,493		799
Payments of long-term debt, including make-whole premiums	(1,795)		(2,968)		(1,724)


Payment of debt issuance costs	(36)		(38)		(8)

Payment of dividends on Common Stock	(440)		(385)		(392)
Payment of dividends on Preferred Stock	(49)		(107)		(137)
Proceeds from issuance of Common Stock, net	—		—		672
Proceeds from issuance of Series C Preferred stock, net	—		—		723

Other financing activities, net	(7)		(5)		(6)
Net cash provided by (used in) financing activities	(345)		1,916		(834)
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	(163)		87		(104)
Cash, Cash Equivalents and Restricted Cash at Beginning of Year	254		167		271
Cash, Cash Equivalents and Restricted Cash at End of Year	$	91	$	254	$	167

See Combined Notes to Consolidated Financial Statements

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED CHANGES IN EQUITY


	2022			2021			2020
	Shares	Amount		Shares	Amount		Shares	Amount
	(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 year	1	$	790	3	$	2,363	2	$	1,740


Issuances of Series C Preferred Stock, net of issuance costs	—	—		—	—		1	723
Conversion of Series B Preferred Stock and Series C Preferred Stock	—	—		(2)	(1,573)		—	(100)
Balance, end of year	1	790		1	790		3	2,363
Common Stock, $0.01 par value; authorized 1,000,000,000 shares
Balance, beginning of year	629	6		551	6		502	5
Issuances related to benefit and investment plans	1	—		1	—		1	—
Issuances of Common Stock	—	—		77	—		48	1
Balance, end of year	630	6		629	6		551	6
Additional Paid-in-Capital
Balance, beginning of year		8,529			6,914			6,080
Issuances related to benefit and investment plans		39			41			30
Issuances of Common Stock, net of issuance costs		—			1			672
Conversion of Series B Preferred Stock and Series C Preferred Stock		—			1,573			100
Recognition of beneficial conversion feature		—			—			32
Balance, end of year		8,568			8,529			6,914
Retained Earnings (Accumulated Deficit)
Balance, beginning of year		154			(845)			632
Net income (loss)		1,057			1,486			(773)
Common Stock dividends declared (see Note 12)		(453)			(404)			(480)
Series A Preferred Stock dividends declared (see Note 12)		(49)			(49)			(73)
Series B Preferred Stock dividends declared (see Note 12)		—			(34)			(85)
Series C Preferred Stock dividends declared (see Note 12)		—			—			(27)
Amortization of beneficial conversion feature		—			—			(32)
Adoption of ASU 2016-13		—			—			(7)



Balance, end of year		709			154			(845)
Accumulated Other Comprehensive Loss
Balance, beginning of year		(64)			(90)			(98)
Other comprehensive income		33			26			8

Balance, end of year		(31)			(64)			(90)
Total Shareholders’ Equity		$	10,042		$	9,415		$	8,348

See Combined Notes to Consolidated Financial Statements

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 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, 2022 and 2021, 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, 2022, 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, 2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022, 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

Impact of Rate Regulation on the Financial Statements — Refer to Notes 2 and 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 by rates. The PUCT’s 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 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 affected account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future 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 uncertainty of decisions by the PUCT included the following, among others:

•We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.

•We read relevant regulatory orders issued by the PUCT for the Company and other public utilities, regulatory statutes, interpretations, procedural memorandums, filings made by intervenors, and other publicly available information 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. We evaluated the external information and compared to management’s recorded regulatory asset and liability balances for completeness.

•For regulatory matters in process, we inspected the Company’s filings with the PUCT and the filings with the PUCT by intervenors that may impact the Company’s future rates, for any evidence that might contradict management’s assertions.

•We evaluated management’s assertion that no indicators of impairment were identified in connection with the Company's property, plant, and equipment. We inspected the capital projects budget and inquired of management to identify projects that are designed to replace assets that may be retired prior to the end of the useful life. We inspected minutes of the board of directors and regulatory orders and other filings with the PUCT to identify any evidence that may contradict management’s assertion regarding probability of a disallowance of long-lived assets.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

February 17, 2023

We have served as the Company’s auditor since 1932.

CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC AND SUBSIDIARIES

(An Indirect, Wholly-Owned Subsidiary of CenterPoint Energy, Inc.)

STATEMENTS OF CONSOLIDATED INCOME


	Year Ended December 31,
	2022		2021		2020
	(in millions)
Revenues	$	3,412	$	3,134	$	2,911

Expenses:
Operation and maintenance	1,650		1,597		1,523
Depreciation and amortization	670		642		560
Taxes other than income taxes	261		251		252
Total	2,581		2,490		2,335
Operating Income	831		644		576

Other Income (Expense):
Interest expense and other finance charges	(202)		(183)		(171)
Interest expense on Securitization Bonds	(13)		(21)		(28)


Other income, net	19		17		10
Total	(196)		(187)		(189)
Income Before Income Taxes	635		457		387
Income tax expense	125		76		53
Net Income	$	510	$	381	$	334

See Combined Notes to Consolidated Financial Statements

CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC AND SUBSIDIARIES

(An Indirect, Wholly-Owned Subsidiary of CenterPoint Energy, Inc.)

STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME


	Year Ended December 31,
	2022		2021		2020
	(in millions)
Net income	$	510	$	381	$	334
Other comprehensive income:

Reclassification of net deferred losses from cash flow hedges (net of tax expense of $-0-, $-0-, and $4, respectively)	—		—		15
Other comprehensive income	—		—		15
Comprehensive income	$	510	$	381	$	349

See Combined Notes to Consolidated Financial Statements

CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC AND SUBSIDIARIES

(An Indirect, Wholly-Owned Subsidiary of CenterPoint Energy, Inc.)

CONSOLIDATED BALANCE SHEETS



	December 31, 2022		December 31, 2021
	(in millions)
ASSETS
Current Assets:
Cash and cash equivalents ($75 and $92 related to VIEs, respectively)	$	75	$	214
Accounts and notes receivable, net ($22 and $29 related to VIEs, respectively), less allowance for credit losses of $1 and $1, respectively	311		263
Accounts and notes receivable—affiliated companies	21		11
Accrued unbilled revenues	142		127
Materials and supplies	471		292



Prepaid expenses and other current assets ($13 and $19 related to VIEs, respectively)	41		49
Total current assets	1,061		956
Property, Plant and Equipment, net	13,461		11,203
Other Assets:
Regulatory assets ($229 and $420 related to VIEs, respectively)	778		789

Other non-current assets	39		32
Total other assets	817		821
Total Assets	$	15,339	$	12,980

See Combined Notes to Consolidated Financial Statements

CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC AND SUBSIDIARIES

(AN INDIRECT, WHOLLY-OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.)

CONDENSED CONSOLIDATED BALANCE SHEETS – (continued)

LIABILITIES AND MEMBER’S EQUITY


	December 31, 2022		December 31, 2021
	(in millions)
LIABILITIES AND MEMBER’S EQUITY
Current Liabilities:
Current portion of VIE Securitization Bonds long-term debt	$	156	$	220
Current portion of other long-term debt	—		300
Accounts payable	413		510
Accounts and notes payable—affiliated companies	755		568
Taxes accrued	150		193
Interest accrued	83		74

Other current liabilities	88		91
Total current liabilities	1,645		1,956
Other Liabilities:
Deferred income taxes, net	1,229		1,122
Benefit obligations	38		55
Regulatory liabilities	1,155		1,152

Other non-current liabilities	77		98
Total other liabilities	2,499		2,427
Long-Term Debt, net:
VIE Securitization Bonds, net	161		317
Other long-term debt, net	6,036		4,658
Total long-term debt, net	6,197		4,975
Commitments and Contingencies (Note 15)
Member’s Equity:
Common stock	—		—
Additional paid-in capital	3,860		2,678
Retained earnings	1,138		944

Total member’s equity	4,998		3,622
Total Liabilities and Member’s Equity	$	15,339	$	12,980

See Combined Notes to Consolidated Financial Statements

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,
	2022		2021		2020
	(in millions)
Cash Flows from Operating Activities:
Net income	$	510	$	381	$	334
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	670		642		560
Deferred income taxes	86		32		(42)
Changes in other assets and liabilities:
Accounts and notes receivable, net	(63)		(17)		(26)
Accounts receivable/payable–affiliated companies	47		(36)		47
Inventory	(179)		(97)		(48)
Accounts payable	(7)		66		28

Net regulatory assets and liabilities	(41)		(237)		(11)
Other current assets and liabilities	(20)		39		55
Other non-current assets and liabilities	(25)		6		4
Other operating activities, net	(12)		(9)		(2)
Net cash provided by operating activities	966		770		899
Cash Flows from Investing Activities:
Capital expenditures	(2,436)		(1,619)		(1,058)
Decrease in notes receivable–affiliated companies	—		—		481


Other investing activities, net	1		2		13
Net cash used in investing activities	(2,435)		(1,617)		(564)
Cash Flows from Financing Activities:

Proceeds from long-term debt	1,589		1,096		299
Payments of long-term debt	(720)		(613)		(231)

Dividend to parent	(316)		—		(551)
Increase in notes payable–affiliated companies	130		504		8

Payment of debt issuance costs	(17)		(12)		(3)
Contribution from parent	1,143		130		62
Payment of obligation for finance lease	(485)		(179)		—

Net cash provided by (used in) financing activities	1,324		926		(416)
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	(145)		79		(81)
Cash, Cash Equivalents and Restricted Cash at Beginning of the Year	233		154		235
Cash, Cash Equivalents and Restricted Cash at End of the Year	$	88	$	233	$	154

See Combined Notes to Consolidated Financial Statements

CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC AND SUBSIDIARIES

(An Indirect, Wholly-Owned Subsidiary of CenterPoint Energy, Inc.)

STATEMENTS OF CONSOLIDATED CHANGES IN EQUITY


	2022			2021			2020
	Shares	Amount		Shares	Amount		Shares	Amount
	(in millions, except share amounts)


Common Stock
Balance, beginning of year	1,000	$	—	1,000	$	—	1,000	$	—
Balance, end of year	1,000	—		1,000	—		1,000	—
Additional Paid-in-Capital
Balance, beginning of year		2,678			2,548			2,486
Non-cash contribution from parent		38			—			—
Contribution from parent		1,143			130			62
Other		1			—			—
Balance, end of year		3,860			2,678			2,548
Retained Earnings
Balance, beginning of year		944			563			780
Net income		510			381			334
Dividend to parent		(316)			—			(551)
Balance, end of year		1,138			944			563
Accumulated Other Comprehensive Loss
Balance, beginning of year		—			—			(15)
Other comprehensive income		—			—			15
Balance, end of year		—			—			—
Total Member’s Equity		$	4,998		$	3,622		$	3,111

See Combined Notes to Consolidated Financial Statements

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, 2022 and 2021, 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, 2022, 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, 2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

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.

Critical Audit Matter

Impact of Rate Regulation on the Financial Statements — Refer to Notes 2, 4 and 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.

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.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the uncertainty of decisions by the Commissions included the following, among others:

•We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

February ~~22, 2018~~17, 2023

We have served as the Company’s auditor since 1997.

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

(An Indirect, Wholly-Owned Subsidiary of CenterPoint Energy, Inc.)

STATEMENTS OF CONSOLIDATED INCOME


	Year Ended December 31,										Year Ended December 31,
	2017			2016			2015				2022		2021		2020
	(in millions)										(in millions)
Revenues:										Revenues:
Utility revenues	$	2,606		$	2,380		$	2,603		Utility revenues	$	4,764	$	4,143	$	3,479
Non-utility revenues	3,997			2,074			1,924			Non-utility revenues	36		57		52
Total	6,603			4,454			4,527			Total	4,800		4,200		3,531

Expenses:										Expenses:
Utility natural gas	1,109			983			1,264			Utility natural gas	2,607		1,885		1,313
Non-utility natural gas	3,785			1,983			1,838
Non-utility cost of revenue, including natural gas										Non-utility cost of revenue, including natural gas	4		17		17
Operation and maintenance	839			777			741			Operation and maintenance	886		973		997
Depreciation and amortization	279			249			227			Depreciation and amortization	448		483		441
Taxes other than income taxes	147			144			144			Taxes other than income taxes	257		249		234

Total	6,159			4,136			4,214			Total	4,202		3,607		3,002
Operating Income	444			318			313			Operating Income	598		593		529

Other Income (Expense):										Other Income (Expense):
Interest and other finance charges	(123		)	(122		)	(137		)
Equity in earnings (losses) of unconsolidated affiliates	265			208			(1,633		)
Gain on sale										Gain on sale	557		11		—
Interest expense and other finance charges										Interest expense and other finance charges	(130)		(134)		(143)

Other, net	(2		)	3			6			Other, net	(64)		(4)		(4)
Total	140			89			(1,764		)	Total	363		(127)		(147)
Income (Loss) Before Income Taxes	584			407			(1,451		)
Income From Continuing Operations Before Income Taxes										Income From Continuing Operations Before Income Taxes	961		466		382
Income tax expense (benefit)	(161		)	162			(539		)	Income tax expense (benefit)	236		76		117
Net Income (Loss)	$	745		$	245		$	(912	)
Income From Continuing Operations										Income From Continuing Operations	725		390		265
Loss from Discontinued Operations (net of tax benefit of $—, $—, and $(2), respectively)										Loss from Discontinued Operations (net of tax benefit of $—, $—, and $(2), respectively)	—		—		(66)
Net Income										Net Income	$	725	$	390	$	199

See Combined Notes to Consolidated Financial Statements

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

(An Indirect, Wholly-Owned Subsidiary of CenterPoint Energy, Inc.)

STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME

Year Ended December 31,
2017 2016 2015
(in millions)
Net income (loss) $ 745
$ 245
$ (912 )
Other comprehensive income (loss), net of tax:

Adjustment to postretirement and other postemployment plans (net of tax of $4, $4 and $6) 4
(6 ) 8
Net deferred loss from cash flow hedges (net of tax of $1, $-0-, and $-0-, respectively)

(1 ) —
—
Other comprehensive income (loss) 3
(6 ) 8
Comprehensive income (loss) $ 748
$ 239
$ (904 )


	Year Ended December 31,
	2022		2021		2020
	(in millions)
Net income	$	725	$	390	$	199
Other comprehensive income:
Adjustment to other postemployment plans (net of tax expense of $4, $1 and $1, respectively)	6		—		—

Other comprehensive income	6		—		—
Comprehensive income	$	731	$	390	$	199

See Combined Notes to Consolidated Financial Statements

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

(An Indirect, Wholly-Owned Subsidiary of CenterPoint Energy, Inc.)

CONSOLIDATED BALANCE SHEETS


	December 31,
	2017		2016			December 31, 2022		December 31, 2021
	(in millions)					(in millions)
ASSETS					ASSETS
Current Assets:					Current Assets:
Cash and cash equivalents	$	12	$	1	Cash and cash equivalents	$	—	$	15
Accounts receivable, less bad debt reserve of $18 million and $14 million, respectively	713		512
Accrued unbilled revenue	307		229
Accounts receivable, less allowance for credit losses of $34 and $40, respectively					Accounts receivable, less allowance for credit losses of $34 and $40, respectively	463		336
Accrued unbilled revenue, less allowance for credit losses of $4 and $6, respectively					Accrued unbilled revenue, less allowance for credit losses of $4 and $6, respectively	573		335
Accounts and notes receivable — affiliated companies	6		5		Accounts and notes receivable — affiliated companies	52		28
Material and supplies	56		47		Material and supplies	98		82
Natural gas inventory	222		131		Natural gas inventory	195		151
Non-trading derivative assets	110		51		Non-trading derivative assets	7		8
Taxes receivable					Taxes receivable	12		28

Current assets held for sale					Current assets held for sale	—		2,084
Regulatory assets					Regulatory assets	1,336		1,371
Prepaid expenses and other current assets	166		81		Prepaid expenses and other current assets	78		48
Total current assets	1,592		1,057		Total current assets	2,814		4,486
Property, Plant and Equipment, Net	4,852		4,569		Property, Plant and Equipment, Net	10,406		9,108
Other Assets:					Other Assets:
Goodwill	867		862		Goodwill	1,583		1,583
Regulatory assets					Regulatory assets	844		938
Non-trading derivative assets	44		19		Non-trading derivative assets	2		4
Investment in unconsolidated affiliates	2,472		2,505
Other	285		206

Other non-current assets					Other non-current assets	55		34
Total other assets	3,668		3,592		Total other assets	2,484		2,559
Total Assets	$	10,112	$	9,218	Total Assets	$	15,704	$	16,153

See Combined Notes to Consolidated Financial Statements

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

(An Indirect, Wholly-Owned Subsidiary of CenterPoint Energy, Inc.)

CONSOLIDATED BALANCE SHEETS, cont.


	December 31,
	2017		2016			December 31, 2022		December 31, 2021
	(in millions)					(in millions)
LIABILITIES AND STOCKHOLDER’S EQUITY					LIABILITIES AND STOCKHOLDER’S EQUITY

Current Liabilities:					Current Liabilities:
Short-term borrowings	$	39	$	35	Short-term borrowings	$	511	$	7
Current portion of long-term debt	—		250		Current portion of long-term debt	1,331		—
Accounts payable	669		471		Accounts payable	690		503
Accounts and notes payable — affiliated companies	611		40
Accounts and notes payable–affiliated companies					Accounts and notes payable–affiliated companies	190		566

Taxes accrued	75		73		Taxes accrued	140		143
Interest accrued	32		33		Interest accrued	50		30
Customer deposits	76		80		Customer deposits	94		92
Non-trading derivative liabilities	20		41
Other	137		124

Current liabilities held for sale					Current liabilities held for sale	—		562
Other current liabilities					Other current liabilities	200		151
Total current liabilities	1,659		1,147		Total current liabilities	3,206		2,054

Other Liabilities:					Other Liabilities:
Deferred income taxes, net	1,289		1,925		Deferred income taxes, net	1,262		1,028
Non-trading derivative liabilities	4		5

Benefit obligations	97		104		Benefit obligations	76		100
Regulatory liabilities	1,201		769		Regulatory liabilities	1,801		1,715
Other	297		221

Other non-current liabilities					Other non-current liabilities	501		571
Total other liabilities	2,888		3,024		Total other liabilities	3,640		3,414

Long-Term Debt, net	2,457		2,125		Long-Term Debt, net	3,495		5,552
Commitments and Contingencies (Note 14)

Commitments and Contingencies (Note 15)					Commitments and Contingencies (Note 15)

Stockholder’s Equity:					Stockholder’s Equity:
Common stock	—		—		Common stock	—		—
Paid-in capital	2,528		2,489
Additional paid-in capital					Additional paid-in capital	3,729		4,106
Retained earnings	574		430		Retained earnings	1,618		1,017
Accumulated comprehensive income	6		3
Accumulated other comprehensive income					Accumulated other comprehensive income	16		10
Total stockholder’s equity	3,108		2,922		Total stockholder’s equity	5,363		5,133
Total Liabilities And Stockholder’s Equity	$	10,112	$	9,218

Total Liabilities and Stockholder’s Equity					Total Liabilities and Stockholder’s Equity	$	15,704	$	16,153



(Mark One)
þ☑			ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

			FOR THE FISCAL YEAR ENDED DECEMBER 31, ~~2017~~2022
OR
¨☐			TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

			FOR THE TRANSITION PERIOD FROM TO

207-1111

1-13265	CenterPoint Energy Resources Corp.			76-0511406
	(a Delaware corporation)
	1111 Louisiana
	Houston,	Texas	77002
	(713)	207-1111


Securities registered pursuant to Section 12(b) of the Act:
Registrant	Title of each class	Trading 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, LLC	6.95% General Mortgage Bonds due 2033	n/a	New York Stock Exchange
CenterPoint Energy Resources Corp.	6.625% Senior Notes due 2037	n/a	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:
None


GLOSSARY
ACE		Affordable Clean Energy


~~GLOSSARY~~
~~ADFIT~~AFSI		~~Accumulated deferred federal~~Adjusted financial statement income ~~taxes~~
~~AEM~~AFUDC		~~Atmos Energy Marketing, LLC, previously a wholly-owned subsidiary of Atmos Energy Holdings, Inc., a wholly-owned subsidiary of Atmos Energy Corporation~~
~~AFUDC~~	Allowance for funds used during construction
~~AMAs~~AGC		Alcoa Generating Corporation, a subsidiary of Alcoa, Inc.

AMAs		Asset Management Agreements
~~APSC~~AMI		~~Arkansas Public Service Commission~~Advanced Metering Infrastructure
~~ArcLight~~AMS		~~ArcLight Capital Partners, LLC~~Advanced Metering System
~~ARO~~


Arevon		Arevon Energy, Inc., which was formed through the combination of Capital Dynamics, Inc.’s U.S. Clean Energy Infrastructure business unit and Arevon Asset Management
ARO		Asset retirement obligation
~~ASC~~ARP		Alternative revenue program
ASC		Accounting Standards Codification
~~ASU~~Asset Purchase Agreement		Asset 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.
ASU		Accounting Standards Update
~~Bcf~~AT&T		AT&T Inc.
AT&T Common		AT&T common stock
Bailey to Jones Creek Project		A transmission project in the greater Freeport, Texas area, which includes enhancements to two existing substations and the construction of a new 345 kV double-circuit line located in the counties of Brazoria, Matagorda and Wharton

Bcf		Billion cubic feet
~~Btu~~		~~British thermal units~~
~~BDA~~		~~Billing 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~~
~~CEA~~Bond Companies		~~Commodities Exchange Act~~Bond Company IV and Restoration Bond Company, each a wholly-owned, bankruptcy remote entity formed solely for the purpose of purchasing and owning transition or system restoration property through the issuance of Securitization Bonds
~~CEIP~~

Bond Company IV		CenterPoint Energy Transition Bond Company IV, LLC, a wholly-owned subsidiary of Houston Electric

BTA		Build Transfer Agreement
CARES Act		Coronavirus Aid, Relief, and Economic Security Act
CCR		Coal Combustion Residuals

CECA		Clean Energy Cost Adjustment

CEIP		CenterPoint Energy Intrastate Pipelines, LLC, a wholly-owned subsidiary of CERC Corp.
CenterPoint Energy		CenterPoint Energy, Inc., and its subsidiaries
CERC Corp.		CenterPoint Energy Resources Corp.
CERC		CERC Corp., together with its subsidiaries
CERCLA		Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended
CES		CenterPoint 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
~~CFTC~~		~~Commodity Futures Trading Commission~~
~~CIP~~	~~Conservation Improvement Program~~
~~COLI~~	~~Corporate-owned life insurance~~
~~Continuum~~	The retail energy services business 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, LLC
~~Dodd-Frank Act~~	~~Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010~~
~~DOE~~	~~U.S. Department of Energy~~
~~DOT~~	~~U.S. Department of Transportation~~
~~Dth~~	~~Dekatherms~~
~~EBITDA~~	~~Earnings before interest, taxes, depreciation and amortization~~
~~EDIT~~	~~Excess deferred income taxes~~
~~EECR~~	~~Energy Efficiency Cost Recovery~~
~~EGT~~	~~Enable Gas Transmission, LLC~~
~~EIA~~	~~U.S. Energy Information Administration~~
~~Enable~~	~~Enable Midstream Partners, LP~~
~~EPA~~	~~Environmental Protection Agency~~
~~EPAct of 2005~~	~~Energy Policy Act of 2005~~
~~FASB~~	~~Financial Accounting Standards Board~~
~~FERC~~	~~Federal Energy Regulatory Commission~~
~~Fitch~~	~~Fitch, Inc.~~
~~FRP~~	~~Formula Rate Plan~~
~~Gas Daily~~	~~Platts gas daily indices~~
~~GenOn~~	~~GenOn Energy, Inc.~~
~~GHG~~	~~Greenhouse gases~~



~~GLOSSARY (cont.)~~Charter Common						Charter Communications, Inc. common stock
~~GRIP~~						~~Gas Reliability Infrastructure Program~~
~~Houston Electric~~
CIP						Conservation Improvement Program

CNG						Compressed natural gas

Code						The Internal Revenue Code of 1986, as amended
CODM						Chief Operating Decision Maker
Common Stock						CenterPoint Energy, ~~Houston Electric, LLC and its subsidiaries~~Inc. common stock, par value $0.01 per share
~~HVAC~~Compensation Committee						~~Heating, ventilation and air conditioning~~Compensation Committee of the Board of Directors of CenterPoint Energy
~~IBEW~~COVID-19						~~International Brotherhood of Electrical Workers~~Novel coronavirus disease 2019, and any mutations or variants thereof, and related global outbreak that was subsequently declared a pandemic by the World Health Organization
~~ICA~~CPCN						~~Interstate Commerce Act~~Certificate of ~~1887~~public convenience and necessity
~~IRS~~						~~Internal Revenue Service~~
~~LIBOR~~						~~London Interbank Offered Rate~~
~~LNG~~CPP						~~Liquefied natural gas~~Clean Power Plan
~~LPSC~~CSIA						~~Louisiana Public Service Commission~~Compliance and System Improvement Adjustment
~~MGPs~~						~~Manufactured gas plants~~
~~MLP~~						~~Master Limited Partnership~~
~~MMBtu~~						~~One million British thermal units~~
~~MMcf~~DCRF						~~Million cubic feet~~Distribution Cost Recovery Factor
~~Moody’s~~DE&I Council						~~Moody’s Investors Service, Inc.~~Diversity, Equity and Inclusion Council



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)						$18,490,009,390
CenterPoint Energy Houston Electric, LLC						None
CenterPoint Energy Resources Corp.						None


CenterPoint Energy, Inc.	629,788,724	shares of common stock outstanding, excluding 166 shares held as treasury stock
CenterPoint Energy Houston Electric, LLC	1,000	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.


~~MPSC~~				~~Mississippi Public Service Commission~~GLOSSARY
~~MPUC~~DOC			~~Minnesota Public Utilities Commission~~U.S. Department of Commerce
~~MRT~~			~~Enable-Mississippi River Transmission, LLC~~
~~NAV~~DOT			~~Net asset value~~U.S. Department of Transportation
~~NESHAPS~~DRR			~~National Emission Standards for Hazardous Air Pollutants~~Distribution Replacement Rider
~~NGA~~DSMA			~~Natural Gas Act of 1938~~Demand Side Management Adjustment
~~NGD~~Dth			~~Natural gas distribution business~~Dekatherms
~~NGLs~~EBITDA			~~Natural gas liquids~~Earnings before income taxes, depreciation and amortization
~~NGPA~~ECA			~~Natural Gas Policy Act of 1978~~Environmental Cost Adjustment
~~NGPSA~~EDF Renewables			~~Natural Gas Pipeline Safety Act of 1968~~EDF Renewables Development, Inc.
~~NRG~~			~~NRG Energy, Inc.~~
~~NYMEX~~EDIT			~~New York Mercantile Exchange~~Excess deferred income taxes
~~NYSE~~EECR			~~New York Stock Exchange~~Energy Efficiency Cost Recovery
~~OCC~~EECRF			~~Oklahoma Corporation Commission~~Energy Efficiency Cost Recovery Factor
~~OGE~~EEFC			~~OGE~~ Energy ~~Corp.~~Efficiency Funding Component
~~PBRC~~EEFR			~~Performance Based Rate Change~~Energy Efficiency Funding Rider
~~PHMSA~~			~~Pipeline and Hazardous Materials Safety Administration~~
~~PRPs~~			~~Potentially responsible parties~~
~~Railroad Commission~~ELG			~~Railroad Commission of Texas~~Effluent Limitation Guidelines
~~RCRA~~			~~Resource Conservation and Recovery Act~~
~~REIT~~Elk GP Merger Sub			~~Real Estate Investment Trust~~Elk GP Merger Sub LLC, a Delaware limited liability company and a direct wholly-owned subsidiary of Energy Transfer
~~Reliant~~Elk Merger Sub			Elk Merger Sub LLC, a Delaware limited liability company and a direct wholly-owned subsidiary of Energy	~~Reliant Energy, Incorporated~~ Transfer
~~RICE MACT~~Enable			~~Reciprocating Internal Combustion Engines Maximum Achievable Control Technology~~Enable Midstream Partners, LP
~~ROE~~Enable Common Units			~~Return on equity~~Enable common units, representing limited partnership interests in Enable
~~RRA~~Enable GP			~~Rate Regulation Adjustment~~Enable GP, LLC, a Delaware limited liability company and the general partner of Enable
~~RRI~~Enable Merger			~~Reliant Resources, Inc.~~The merger of Elk 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
~~RSP~~Enable Merger Agreement			~~Rate Stabilization~~Agreement 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
~~SEC~~		~~Securities and Exchange Commission~~
~~SESH~~	~~Southeast Supply Header, LLC~~
Enable Series A Preferred Units		Enable’s 10% Series A Fixed-to-Floating Non-Cumulative Redeemable Perpetual Preferred Units, representing limited partner interests in Enable
~~S&P~~			~~Standard & Poor’s Ratings~~
Energy Services			Offered 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 Group			Substantially 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 Group			Energy Systems Group, LLC, a ~~division~~wholly-owned subsidiary of ~~The McGraw-Hill Companies~~Vectren
Energy Transfer			Energy Transfer LP, a Delaware limited partnership
Energy Transfer Common Units			Energy Transfer common units, representing limited partner interests in Energy Transfer
Energy Transfer GP			LE GP, LLC, a Delaware limited liability company and sole general partner of Energy Transfer
Energy Transfer Series G Preferred Units			Energy Transfer Series G Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units, representing limited partner interests in Energy Transfer
EPA			Environmental Protection Agency

Equity Purchase Agreement			Equity Purchase Agreement, dated as of February 24, 2020, by and between CERC Corp. and Symmetry Energy Solutions Acquisition (f/k/a Athena Energy Services Buyer, LLC)
ERCOT			Electric Reliability Council of Texas
ERCOT ISO			ERCOT Independent System Operator
ERISA			Employee Retirement Income Security Act of 1974
ERG			Employee Resource Group
ERO			Electric Reliability Organization

ESPC			Energy Savings Performance Contract
FAC			Fuel Adjustment Clause


GLOSSARY
February 2021 Winter Storm Event						The extreme and unprecedented winter weather event in February 2021 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.
FERC						Federal Energy Regulatory Commission

Fitch						Fitch Ratings, Inc.
Form 10-K						Annual Report on Form 10-K
FPA						Federal Power Act


~~GLOSSARY (cont.)~~
~~TBD~~General Mortgage						General Mortgage Indenture, dated as of October 10, 2002, between CenterPoint Energy Houston Electric, LLC and JPMorgan Chase Bank, as Trustee, as supplemented
GHG						Greenhouse gases

GRIP						Gas Reliability Infrastructure Program
GWh						Gigawatt-hours

HLPSA						Hazardous Liquid Pipeline Safety Act of 1979
Houston Electric						CenterPoint Energy Houston Electric, LLC and its subsidiaries
HVAC						Heating, ventilation and air conditioning
IBEW						International Brotherhood of Electrical Workers

ICPA						Inter-Company Power Agreement
IDEM						Indiana Department of Environmental Management

Indiana Electric						Operations of SIGECO’s electric transmission and distribution services, and includes its power generating and wholesale power operations
Indiana Gas						Indiana Gas Company, Inc., a wholly-owned subsidiary of CERC Corp.
Indiana North						Gas operations of Indiana Gas
Indiana South						Gas operations of SIGECO
Indiana Utilities						Indiana Electric, Indiana North and Indiana South, collectively
Infrastructure Services						Provided underground pipeline construction and repair services through VISCO and its wholly-owned subsidiaries, Miller Pipeline, LLC and Minnesota Limited, LLC
Infrastructure Services Disposal Group						Businesses within the Infrastructure Services reporting unit that were sold under the Securities Purchase Agreement
IRA						Inflation Reduction Act of 2022
IRP						Integrated Resource Plan
IRS						Internal Revenue Service
IURC						Indiana Utility Regulatory Commission
kV						Kilovolt

LDC						Local Distribution Company
LIBOR						London Interbank Offered Rate
LNG						Liquefied natural gas
Load Shed						Curtailing the amount of electricity a TDU can transmit and distribute to its customers
LPSC						Louisiana Public Service Commission
LTIPs						Long-term incentive plans

MCRA						MISO Cost and Revenue Adjustment

M&DOT						Mortgage 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
Merger						The 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 Agreement						Agreement and Plan of Merger, dated as of April 21, 2018, among CenterPoint Energy, Vectren and Merger Sub
Merger Date						February 1, 2019
Merger Sub						Pacer Merger Sub, Inc., an Indiana corporation and wholly-owned subsidiary of CenterPoint Energy
MES						CenterPoint Energy Mobile Energy Solutions, Inc. (now known as Mobile Energy Solutions, Inc.), previously a wholly-owned subsidiary of CERC Corp.


GLOSSARY
MGP						Manufactured gas plant
MISO						Midcontinent Independent System Operator


MMcf						Million cubic feet
Moody’s						Moody’s Investors Service, Inc.



MPSC						Mississippi Public Service Commission
MPUC						Minnesota Public Utilities Commission

Mva						Megavolt amperes
MW						Megawatts

Natural Gas						Natural gas distribution businesses
NECA						National Electrical Contractors Association
NERC						North American Electric Reliability Corporation

NGA						Natural Gas Act of 1938

NGLs						Natural gas liquids
NGPA						Natural Gas Policy Act of 1978
NGPSA						Natural Gas Pipeline Safety Act of 1968

NOLs						Net operating losses
NRG						NRG Energy, Inc.

NYSE						New York Stock Exchange

OGE						OGE Energy Corp.

OPEIU						Office & Professional Employees International Union
Oriden						Oriden LLC
Origis						Origis Energy USA Inc.
OUCC						Indiana Office of Utility Consumer Counselor
OVEC						Ohio Valley Electric Corporation




PHMSA						Pipeline and Hazardous Materials Safety Administration

Pipes Act						Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2020

PowerTeam Services						PowerTeam Services, LLC, a Delaware limited liability company, now known as Artera Services, LLC
PPA						Power purchase agreement
PRPs						Potentially responsible parties

PTCs						Production Tax Credits
PUCO						Public Utilities Commission of Ohio
PUCT						Public Utility Commission of Texas
Railroad Commission						Railroad Commission of Texas
RCRA						Resource Conservation and Recovery Act of 1976

READY						CenterPoint Energy’s serious injury and fatality prevention model. READY stands for Recognize, Evaluate, Anticipate, Define, Yes
Registrants						CenterPoint Energy, Houston Electric and CERC, collectively
Reliant Energy						Reliant Energy, Incorporated
REP						Retail electric provider
Restoration Bond Company						CenterPoint Energy Restoration Bond Company, LLC, a wholly-owned subsidiary of Houston Electric


Restructuring						CERC Corp.’s common control acquisition of Indiana Gas and VEDO from VUH on June 30, 2022
ROE						Return on equity

ROU						Right of use
RRA						Rate Regulation Adjustment

RSP						Rate Stabilization Plan
Scope 1 emissions						Direct source of emissions from a company’s operations
Scope 2 emissions						Indirect source of emissions from a company’s energy usage


GLOSSARY
Scope 3 emissions						Indirect source of emissions from a company’s end-users
SEC						Securities and Exchange Commission

Securities Purchase Agreement						Securities Purchase Agreement, dated as of February 3, 2020, by and among VUSI, PowerTeam Services and, solely for purposes of Section 10.17 of the Securities Purchase Agreement, Vectren
Securitization Bonds						Transition and system restoration bonds
Series A Preferred Stock						CenterPoint Energy’s 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 Stock						CenterPoint Energy’s 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 Stock						CenterPoint Energy’s Series C Mandatory Convertible Preferred Stock, par value $0.01 per share, with a liquidation preference of $1,000 per share

SIGECO						Southern Indiana Gas and Electric Company, a wholly-owned subsidiary of Vectren
SOFR						Secured Overnight Financing Rate
S&P						S&P Global Ratings, a division of S&P Global Inc.
SRC						Sales Reconciliation Component
Symmetry Energy Solutions Acquisition						Symmetry Energy Solutions Acquisition, LLC, a Delaware limited liability company (f/k/a Athena Energy Services Buyer, LLC) and subsidiary of Energy Capital Partners, LLC
TBD						To be determined
~~TCJA~~
TCJA						Tax reform legislation informally called the Tax Cuts and Jobs Act of 2017
~~Transition Agreements~~TCOS						~~Services Agreement, Employee Transition Agreement, Transitional Seconding Agreement and other agreements entered into in connection with the formation~~Transmission Cost of ~~Enable~~Service
~~VaR~~TCRF						~~Value at Risk~~Transmission Cost Recovery Factor
~~VIE~~TDSIC						Transmission, Distribution and Storage System Improvement Charge
TDU						Transmission and distribution utility
TEEEF						Assets leased or costs incurred as “temporary emergency electric energy facilities” under Section 39.918 of the Public Utility Regulatory Act, also referred to as mobile generation



Texas RE						Texas Reliability Entity

TSA						Transportation Security Administration



UESC						Utility Energy Services Contract
USW						United Steelworkers Union
UWUA						Utility Workers Union of America
Utility Holding						Utility Holding, LLC, a wholly-owned subsidiary of CenterPoint Energy


Vectren						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.
VEDO						Vectren 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
VIE						Variable interest entity
~~2002 Act~~VISCO						~~Pipeline Safety Improvement Act~~Vectren Infrastructure Services Corporation, formerly a wholly-owned subsidiary of ~~2002~~Vectren
~~2006 Act~~Vistra Energy Corp.						~~Pipeline Inspection, Protection, Enforcement~~Texas-based energy company focused on the competitive energy and ~~Safety Act of 2006~~power generation markets, whose major subsidiaries include Luminant and TXU Energy
~~2011 Act~~VRP						~~Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011~~ Voluntary Remediation Program
~~2016 Act~~VUH						~~Protecting our Infrastructure~~Vectren 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 ~~Pipelines~~Vectren
VUH PPNs						VUH’s private senior guaranteed notes
VUSI						Vectren Utility Services, Inc., a wholly-owned subsidiary of Vectren
WBD Common						Warner Bros. Discovery, Inc. Series A common stock
Winter Storm Elliott						From December 21 to 26, 2022, a historic extratropical cyclone created winter storm conditions, including blizzards, high winds, snowfall and ~~Enhancing Safety Act~~ record cold temperatures across the majority of ~~2016~~ the United States and parts of Canada.

ZENS						2.0% Zero-Premium Exchangeable Subordinated Notes due 2029


GLOSSARY
ZENS-Related Securities						As of December 31, 2022, consisted of AT&T Common, Charter Common and WBD Common and as of December 31, 2021, consisted of AT&T Common and Charter Common
2021 Form 10-K						Annual Report on Form 10-K for the fiscal year ended December 31, 2021
2022 Annuity Lift-Out						The irrevocable group annuity contract purchased in December 2022 from an insurance company to transfer $138 million of CenterPoint Energy’s pension plan’s outstanding benefit obligation


	REPs	Residential	Commercial/ Industrial	Total Customers
Texas gulf coast	64	2,402,329	304,269	2,706,598


	Residential	Commercial/Industrial	Total Customers
Southwestern Indiana	132,402	19,249	151,651


	2022
Total load at peak	1,020

Generating capability	1,212
Purchase supply (effective capacity)	36
Interruptible contracts & direct load control	9
Total power supply capacity	1,257
Reserve margin at peak	23	%


~~PART I~~



	Residential	Commercial/ Industrial	Total Customers
Arkansas	378,429	47,965	426,394
Louisiana	230,084	16,711	246,795
Minnesota	788,832	70,178	859,010
Mississippi	113,752	12,567	126,319
Oklahoma	89,074	10,758	99,832
Texas	1,612,969	98,472	1,711,441
Total NGD	3,213,140	256,651	3,469,791



~~Supplier~~		~~Percent of Supply Volumes~~
~~Tenaska Marketing Ventures~~		~~18.0%~~
~~Macquarie Energy, LLC~~		~~12.5%~~
~~BP Energy Company/BP Canada Energy Marketing~~		~~12.1%~~
~~Kinder Morgan Tejas Pipeline/Kinder Morgan Texas Pipeline~~		~~7.4%~~
~~CES~~		~~5.4%~~
~~Mieco, Inc.~~		~~5.0%~~
~~Spire Marketing, Inc.~~		~~4.9%~~
~~United Energy Trading, LLC~~		~~4.7%~~
~~Koch Energy Services, LLC~~		~~4.0%~~
~~Cargill~~		~~2.8%~~


PPA with	Location	Expected Date in Service	Capacity (MW)	Term (in Years)
Clenera	Warrick County, Indiana	2025	100	25
Oriden	Vermillion County, Indiana	2025	185	15
Origis	Knox County, Indiana	2024	150	20
			435


Sunrise LLC	88	%
Peabody Coal Sales LLC	11	%
Total of major suppliers	99	%


			(In tons, except average cost per ton)
Coal purchased for generating electricity			2,398,365
Coal inventory as of December 31, 2022			420,750
Average cost of coal per ton			$58.32


	Residential	Commercial/ Industrial/Transportation	Total Customers
Indiana (Indiana Gas)	590,048	54,957	645,005
Louisiana	232,040	16,279	248,319
Minnesota	839,278	72,239	911,517
Mississippi	122,054	13,169	135,223
Ohio	305,741	24,388	330,129
Texas	1,770,565	110,152	1,880,717
Total CERC Natural Gas	3,859,726	291,184	4,150,910
Indiana (SIGECO)	104,495	10,650	115,145
Total CenterPoint Energy Natural Gas	3,964,221	301,834	4,266,055


	CenterPoint Energy		CERC
Tenaska Marketing Ventures, LLC	34	%	32	%
Macquarie Energy, LLC	15	%	15	%
Koch Energy Services, LLC	10	%	11	%

Total of major suppliers	59	%	58	%



	2017		2018		2019		2020		2021		2022
	(in millions)
Natural Gas Distribution	$	523	$	635	$	612	$	637	$	664	$	687
Energy Services	11		20		15		15		15		15
Total	$	534	$	655	$	627	$	652	$	679	$	702



Contractual Obligations	Total		2018		2019-2020		2021-2022		2023 and thereafter
	(in millions)
Long-term debt	$	2,457	$	—	$	—	$	1,491	$	966
Interest payments — long-term debt (1)	1,455		98		196		144		1,017
Short-term borrowings	39		39		—		—		—
Operating leases (2)	23		5		7		6		5
Benefit obligations (3)	—		—		—		—		—
Non-trading derivative liabilities	24		20		4		—		—
Other commodity commitments (4)	1,221		463		522		128		108
Total contractual cash obligations (5)	$	5,219	$	625	$	729	$	1,769	$	2,096



Execution Date	Size of Facility		Amount Utilized as of February 9, 2018			Termination Date
(in millions)
March 3, 2016	$	900	$	899	(1)	March 3, 2022


	Year Ended December 31,
	2022 (1)		2021		2022 (1)		2021
	CenterPoint Energy				CERC
	(in millions)
LIFO inventory	$	101	$	101	$	82	$	79


		December 31, 2022						December 31, 2021
	Weighted Average Useful Lives	Property, Plant and Equipment, Gross		Accumulated Depreciation & Amortization		Property, Plant and Equipment, Net		Property, Plant and Equipment, Gross		Accumulated Depreciation & Amortization		Property, Plant and Equipment, Net
	(in years)	(in millions)
CenterPoint Energy
Electric transmission and distribution	36	$	19,154	$	5,317	$	13,837	$	17,156	$	4,658	$	12,498
Electric generation (1)	26	2,120		813		1,307		1,807		1,179		628
Natural gas distribution	32	15,097		4,135		10,962		13,578		3,981		9,597


Finance ROU asset mobile generation	6.5	662		41		621		179		—		179
Other property	23	695		279		416		953		371		582
Total		$	37,728	$	10,585	$	27,143	$	33,673	$	10,189	$	23,484



	Weighted Average Useful Lives	December 31,
	(in years)	2017		2016
		(in millions)
Natural Gas Distribution	28	$	6,735	$	6,219
Energy Services	27	102		83
Other property	14	51		49
Total		6,888		6,351
Accumulated depreciation and amortization:
Natural Gas Distribution		1,968		1,722
Energy Services		35		29
Other property		33		31
Total accumulated depreciation and amortization		2,036		1,782
Property, plant and equipment, net		$	4,852	$	4,569


	Year Ended December 31, 2021
	Equity Method Investment in Enable
	(in millions)
Equity in earnings of unconsolidated affiliate, net	$	1,019
Income from discontinued operations before income taxes	1,019
Income tax expense	201
Net income from discontinued operations	$	818


	Year Ended December 31, 2020
	Equity Method Investment in Enable		Infrastructure Services Disposal Group		Energy Services Disposal Group		Total
	(in millions)
Revenues	$	—	$	250	$	1,167	$	1,417
Expenses:
Non-utility cost of revenues	—		50		1,108		1,158
Operation and maintenance	—		184		34		218

Taxes other than income taxes	—		1		3		4

Total	—		235		1,145		1,380
Operating income	—		15		22		37
Equity in losses of unconsolidated affiliate, net (1)	(1,428)		—		—		(1,428)
Income (loss) from discontinued operations before income taxes	(1,428)		15		22		(1,391)
Loss on classification to held for sale, net (2)	—		(102)		(96)		(198)
Income tax expense (benefit)	(354)		24		(3)		(333)
Net loss from discontinued operations	$	(1,074)	$	(111)	$	(71)	$	(1,256)


	December 2, 2021 (1)
	(in millions)
Current assets	$	594
Non-current assets	11,227
Current liabilities	1,254
Non-current liabilities	3,281
Non-controlling interest	26
Preferred equity	362
Accumulated other comprehensive loss	(1)
Enable partners’ equity	6,899

Reconciliation of Investment in Enable:
CenterPoint Energy’s ownership interest in Enable partners’ equity	$	3,701
CenterPoint Energy’s basis difference	(2,732)

CenterPoint Energy’s equity method investment in Enable	$	969


	Year Ended December 31,
	2021 (1)		2020
	(in millions)
Operating revenues	$	3,466	$	2,463
Cost of sales, excluding depreciation and amortization	1,959		965
Depreciation and amortization	382		420
Goodwill impairment	—		28
Operating income	634		465
Net income attributable to Enable Common Units	461		52
Reconciliation of Equity in Earnings (Losses), net before income taxes:
CenterPoint Energy’s interest	$	248	$	28
Basis difference amortization (2)	92		87
Loss on dilution, net of proportional basis difference recognition	(1)		(2)
Impairment of CenterPoint Energy’s equity method investment in Enable	—		(1,541)
Gain on Enable Merger	680		—
CenterPoint Energy’s equity in earnings (losses), net before income taxes (3)	$	1,019	$	(1,428)


	Year Ended December 31, 2020 (1)
	CenterPoint Energy		CERC
	(in millions)
Transportation revenue	$	34	$	34
Natural gas expense	48		47


	Year Ended December 31, 2022
	Electric		Natural Gas		Corporate and Other		Total
	(in millions)
Revenue from contracts	$	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
	Electric		Natural Gas		Corporate and Other		Total
	(in millions)
Revenue from contracts	$	3,726	$	4,281	$	249	$	8,256
Other (1)	37		55		4		96
Total revenues	$	3,763	$	4,336	$	253	$	8,352


	Accounts Receivable		Other Accrued Unbilled Revenues		Contract Assets		Contract Liabilities
	(in millions)
Opening balance as of December 31, 2021	$	627	$	513	$	15	$	16
Closing balance as of December 31, 2022	858		764		4		45
Increase (decrease)	$	231	$	251	$	(11)	$	29


	Accounts Receivable		Other Accrued Unbilled Revenues
	(in millions)
Opening balance as of December 31, 2021	$	319	$	335
Closing balance as of December 31, 2022	478		573
Increase	$	159	$	238

Business Segment

Number
Represented
by Collective
Bargaining Groups

Natural Gas Distribution

Energy Services