CenterPoint Energy (CNP) 10-K2020 FY Annual report

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

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

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

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

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

This combined Form 10-K is filed separately by three registrants: CenterPoint Energy, Inc., CenterPoint Energy Houston Electric, LLC and CenterPoint Energy Resources Corp. Information contained herein relating to any individual registrant is filed by such registrant solely on its own behalf. Each registrant makes no representation as to information relating exclusively to the other registrants. Except as discussed in Note 14 to the consolidated financial statements, no registrant has an obligation in respect of any other registrant’s debt securities, and holders of such debt securities should not consider the financial resources or results of operations of any registrant other than the obligor in making a decision with respect to such securities.

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

CenterPoint Energy is a public utility holding company and owns interests in Enable, a publicly traded MLP. CenterPoint Energy’s operating subsidiaries own and operate electric transmission, distribution and generation facilities and natural gas distribution facilities and provide energy performance contracting and sustainable infrastructure services.

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

CERC Corp. is an indirect, wholly-owned subsidiary of CenterPoint Energy that owns and operates natural gas distribution facilities in six states, with operating subsidiaries that own and operate permanent pipeline connections through interconnects with various interstate and intrastate pipeline companies, and provide temporary delivery of LNG and CNG throughout the contiguous 48 states.

    

Vectren is an indirect, wholly-owned subsidiary of CenterPoint Energy that engages in regulated operations through three public utilities:

Vectren performs non-utility activities through ESG, which provides energy performance contracting and sustainable infrastructure services.

On February 3, 2020, CenterPoint Energy, through its subsidiary VUSI, entered into the Securities Purchase Agreement to sell the businesses within its Infrastructure Services reportable segment. The transaction closed on April 9, 2020 for $854 million in cash, inclusive of cash received after closing for the working capital adjustment. For further information, see Note 4 to the consolidated financial statements.

Additionally, on February 24, 2020, CenterPoint Energy, through its subsidiary CERC Corp., entered into the Equity Purchase Agreement to sell CES, which represents substantially all of the businesses within the Energy Services reportable segment. This transaction does not include CEIP and its assets or MES. The transaction closed on June 1, 2020 for approximately $365 million in cash, inclusive of cash received after closing for the working capital adjustment. For further information, see Note 4 to the consolidated financial statements.

As of December 31, 2020, CenterPoint Energy’s reportable segments were Electric, Natural Gas and Midstream Investments. Houston Electric and CERC each consist of one reportable segment.

For a discussion of net income by segment, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Results of Operations by Reportable Segment” in Item 7 of Part II of this report. For additional information about the segments, see Note 18 to the consolidated financial statements. From time to time, we consider the acquisition or the disposition of assets or businesses.

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

We make available free of charge on our Internet website our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after we electronically file such reports with, or furnish them to, the SEC. The SEC maintains an Internet website that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC at http://www.sec.gov. Additionally, we make available free of charge on our Internet website:

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

During the fourth quarter of 2020, CenterPoint Energy’s CODM requested that the financial information for the electric businesses be presented on an aggregated basis for review, resulting in one Electric reportable segment, comprised of Houston Electric and Indiana Electric.

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

Houston Electric is a transmission and distribution electric utility that operates wholly within the state of Texas and is a member of ERCOT. ERCOT serves as the independent system operator and regional reliability coordinator for member electric power systems in most of Texas. The ERCOT market represents approximately 90% of the demand for power in Texas and is one of the nation’s largest power markets. The ERCOT market operates under the reliability standards developed by the NERC, approved by the FERC and monitored and enforced by the Texas RE. The PUCT has primary jurisdiction over the ERCOT market to ensure the adequacy and reliability of electricity supply across the state’s main interconnected power transmission grid. Houston Electric does not make direct retail or wholesale sales of electric energy or own or operate any electric generating facilities.

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

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

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

Houston Electric has special purpose subsidiaries consisting of the Bond Companies, which it consolidates. These consolidated special purpose subsidiaries are wholly-owned, bankruptcy remote entities that were formed solely for the purpose of purchasing and owning transition or system restoration property through the issuance of Securitization Bonds, and conducting activities incidental thereto. The Securitization Bonds are repaid through charges imposed on customers in Houston Electric’s service territory. For further discussion of the Securitization Bonds and the outstanding balances as of December 31, 2020 and 2019, see Note 14 to the consolidated financial statements.

Houston Electric serves nearly all of the Houston/Galveston metropolitan area near the Texas Gulf Coast. As of December 31, 2020, Houston Electric’s customers consisted of approximately 64 REPs, which sell electricity to approximately 2.6 million metered customers in Houston Electric’s certificated service area, and municipalities, electric cooperatives and other distribution companies located outside Houston Electric’s certificated service area. Each REP is licensed by, and must meet minimum creditworthiness criteria established by, the PUCT. Houston Electric does not have long-term contracts with any of its customers. It operates using a continuous billing cycle, with meter readings being conducted and invoices being distributed to REPs each business day. For information regarding Houston Electric’s major customers, see Note 18 to the consolidated financial statements.

The table below reflects the number of metered customers in Houston Electric’s service area as of December 31, 2020:

There are no other electric transmission and distribution utilities in Houston Electric’s service area. For another provider of transmission and distribution services to provide such services in Houston Electric’s territory, it would be required to obtain a certificate of convenience and necessity from the PUCT and, depending on the location of the facilities, may also be required to obtain franchises from one or more municipalities. Houston Electric is not aware of any other party intending to enter this business in its service area at this time. Distributed generation (i.e., power generation located at or near the point of consumption) could result in a reduction of demand for Houston Electric’s distribution services but has not been a significant factor to date.

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

Houston Electric holds non-exclusive franchises from certain incorporated municipalities in its service territory. In exchange for the payment of fees, these franchises give Houston Electric the right to use the streets and public rights-of-way of these municipalities to construct, operate and maintain its transmission and distribution system and to use that system to conduct its electric delivery business and for other purposes that the franchises permit. The terms of the franchises, with various expiration dates, typically range from 30 to 40 years.

Indiana Electric consists of SIGECO’s electric transmission and distribution services, including its power generating and wholesale power operations. As of December 31, 2020, Indiana Electric supplied electric service to the following:

Indiana Electric’s newest solar array, which was approved by the IURC in 2018, consists of approximately 150,000 solar panels distributed across 300 acres along Indiana State Road 545 between Troy and New Boston, Indiana. Construction of the 50 MW universal solar array was nearing completion at the end of 2020, and the project was placed in service for southwestern Indiana electric customers in early 2021.

Coal for coal-fired generating stations has been supplied from operators of nearby coal mines as there are substantial coal reserves in the southern Indiana area. Approximately 2.0 million tons were purchased for generating electricity during 2020. Indiana Electric’s coal inventory was approximately 707,000 tons as of December 31, 2020. The average cost of coal per ton purchased and delivered in 2020 was $50.73. Another 173,000 tons are stored off-site to be shipped when plant inventory is reduced. Since August 2014, Indiana Electric has purchased substantially all of its coal from Sunrise Coal, LLC.

As part of its power portfolio, Indiana Electric is a 1.5% shareholder in the OVEC, and based on its participation in the ICPA between OVEC and its shareholder companies, many of whom are regulated electric utilities, Indiana Electric has the right to 1.5% of OVEC’s generating capacity output, which, as of December 31, 2020, was approximately 32 MWs. Per the ICPA, Indiana Electric is charged demand charges which are based on OVEC’s operating expenses, including its financing costs. Those demand charges are available to pass through to customers under Indiana Electric’s fuel adjustment clause. Under the ICPA, and while OVEC’s plants are operating, Indiana Electric is severally responsible for its share of OVEC’s debt obligations. Based on OVEC’s current financing, as of September 30, 2020, Indiana Electric’s 1.5% share of OVEC’s debt obligation equates to between $19 million and $24 million, depending on revolving capacity commitments. Moody’s rates OVEC one notch below investment grade with a positive outlook. Fitch continues to rate OVEC as investment grade with a stable outlook. S&P withdrew its ratings on January 9, 2020 at OVEC’s request. In 2020, Indiana Electric purchased approximately 116 GWh from OVEC. If a default were to occur by a member, any reallocation of the existing debt requires consent of the remaining ICPA participants. If any such reallocation were to occur, Indiana Electric would expect to recover any related costs through the fuel adjustment clause, as it does currently for its 1.5% share. In July 2019, House Bill 6 was enacted in Ohio, which provides financial support to the members of OVEC serving Ohio customers (although Indiana Electric does not serve customers in Ohio). In July 2020, an investigation led by the U.S. Attorney’s Office resulted in a federal grand jury indictment of the Speaker of the Ohio House of Representatives, among other individuals, in connection with a racketeering conspiracy involving the adoption of House Bill 6. In light of the allegations in the indictment, proposed legislation has been introduced that would repeal House Bill 6. The outcome of the U.S. Attorney’s Office investigation and its impact on House Bill 6 is unknown at this time. If the provisions of House Bill 6 are ultimately eliminated, it is unclear whether, and in what form, the Ohio General Assembly would pass new legislation addressing similar issues, which could repeal subsidies associated with House Bill 6.

In April 2008, Indiana Electric executed a capacity contract with Benton County Wind Farm, LLC to purchase as much as 30 MW from a wind farm located in Benton County, Indiana, with IURC approval. The contract expires in 2029. Indiana Electric purchased approximately 76 GWh under this contract in 2020. In December 2009, Indiana Electric executed a 20-year power purchase agreement with Fowler Ridge II Wind Farm, LLC to purchase as much as 50 MW of energy from a wind farm located in Benton and Tippecanoe Counties in Indiana, with the approval of the IURC. Indiana Electric purchased approximately 126 GWh under this contract in 2020. In total, wind resources provided approximately 5% of total GWh sourced in 2020.

Indiana Electric is a member of the MISO, a FERC approved regional transmission organization. The MISO serves the electric transmission needs of much of the Midcontinent region and maintains operational control over Indiana Electric’s electric transmission facilities as well as other utilities in the region. Indiana Electric is an active participant in the MISO energy markets, where it bids its generation into the Day Ahead and Real Time markets and procures power for its retail customers at Locational Marginal Price as determined by the MISO market. MISO-related purchase and sale transactions are recorded using settlement information provided by the MISO. These purchase and sale transactions are accounted for on at least a net hourly position. During 2020, in intervals when purchases from the MISO were in excess of generation sold to the MISO, the net purchases were 742 GWh. During the year ended December 31, 2020, in intervals when sales to the MISO were in excess of purchases from the MISO, the net sales were 385 GWh.

As of December 31, 2020, Indiana Electric had interconnections with Louisville Gas and Electric Company, Duke Energy Shared Services, Inc., Indianapolis Power & Light Company, Hoosier Energy Rural Electric Cooperative, Inc. and Big Rivers Electric Corporation providing the ability to simultaneously interchange approximately 900 MW during peak load periods. Indiana Electric, as required as a member of the MISO, has turned over operational control of the interchange facilities and its own transmission assets to the MISO. Indiana Electric, in conjunction with the MISO, must operate the bulk electric transmission system in accordance with NERC Reliability Standards. As a result, interchange capability varies based on regional transmission system configuration, generation dispatch, seasonal facility ratings and other factors. Indiana Electric is in compliance with reliability standards promulgated by the NERC.

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

For another provider of transmission and distribution services to provide such services in Indiana Electric’s territory, it would be required to obtain a certificate of convenience and necessity from the IURC and, depending on the location of the facilities, may also be required to obtain franchises from one or more municipalities. Indiana Electric is not aware of any other party intending to enter this business in its service area at this time. Distributed generation (i.e., power generation located at or near the point of consumption) could result in reduced demand for Indiana Electric’s distribution services but has not been a significant factor to date.

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

CenterPoint Energy’s and CERC’s Natural Gas engages in regulated intrastate natural gas sales and natural gas transportation and storage for residential, commercial, industrial and transportation customers. See the detail of customers by state below. CenterPoint Energy’s and CERC’s Natural Gas provides permanent pipeline connections through interconnects with various interstate and intrastate pipeline companies through CEIP and temporary delivery of LNG and CNG throughout the lower 48 states through MES, utilizing a fleet of customized equipment to provide continuity of natural gas service when pipeline supply is not available. CenterPoint Energy’s and CERC’s Natural Gas also provides services in Minnesota consisting of residential appliance repair and maintenance services along with HVAC equipment sales and home repair protection plans to natural gas customers in Arkansas, Louisiana, Mississippi, Oklahoma and Texas through a third party.

Upon consummation of the Merger, CenterPoint Energy added the legacy natural gas utility services of Vectren, which includes the natural gas utility operations of Indiana Gas, SIGECO and VEDO and provides natural gas distribution and transportation services to nearly two-thirds of Indiana and west central Ohio, primarily in the west-central area. The Indiana and Ohio service areas contain diversified manufacturing and agriculture-related enterprises.

During the fourth quarter of 2020, CenterPoint Energy and CERC’s CODM requested that the CERC corporate functions be included within the financial results of CenterPoint Energy’s Natural Gas reportable segment for review purposes. See Note 18 to the consolidated financial statements for further information.

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

In 2020, approximately 35% and 39% of CenterPoint Energy’s and CERC’s Natural Gas total throughput was to residential customers and approximately 65% and 61% was to commercial and industrial and transportation customers, respectively.

The table below reflects the number of CenterPoint Energy’s and CERC’s Natural Gas customers by state as of December 31, 2020:

The largest metropolitan areas served in each state are Houston, Texas; Minneapolis, Minnesota; Little Rock, Arkansas; Shreveport, Louisiana; Biloxi, Mississippi; Lawton, Oklahoma; Evansville, Indiana and Dayton, Ohio.

The demand for natural gas sales to residential customers and natural gas sales and transportation for commercial and industrial customers is seasonal and affected by variations in weather conditions. In 2020, approximately 67% of CenterPoint Energy’s Natural Gas total throughput and 68% of CERC’s Natural Gas total throughput occurred in the first and fourth quarters. These patterns reflect the higher demand for natural gas for heating purposes during the colder months.

CenterPoint Energy’s and CERC’s Natural Gas transports their natural gas supplies through various intrastate and interstate pipelines under contracts with remaining terms, including extensions, varying from one to sixteen years. CenterPoint Energy’s and CERC’s Natural Gas anticipates that these gas supply and transportation contracts will be renewed or replaced prior to their expiration.

CenterPoint Energy’s and CERC’s Natural Gas actively engages in commodity price stabilization pursuant to annual gas supply plans presented to and/or filed with each of its state regulatory authorities. These price stabilization activities include use of storage gas and contractually establishing structured prices (e.g., fixed price, costless collars and caps) with CenterPoint Energy’s and CERC’s Natural Gas’ physical gas suppliers. Their gas supply plans generally call for 50–75% of normal winter supplies to be stabilized in some fashion.

The regulations of the states in which CenterPoint Energy’s and CERC’s Natural Gas operates allow them to pass through changes in the cost of natural gas, including savings and costs of financial derivatives associated with the index-priced physical supply, to their customers under purchased gas adjustment provisions in their tariffs. Depending upon the jurisdiction, the purchased gas adjustment factors are updated periodically, ranging from monthly to semi-annually. The changes in the cost of gas billed to customers are subject to review by the applicable regulatory bodies.

CenterPoint Energy’s and CERC’s Natural Gas uses various third-party storage services or owned natural gas storage facilities to meet peak-day requirements and to manage the daily changes in demand due to changes in weather. CenterPoint

The table below reflects CenterPoint Energy’s and CERC’s Natural Gas contracted upstream storage services as of December 31, 2020:

On an ongoing basis, CenterPoint Energy’s and CERC’s Natural Gas enters into contracts to provide sufficient supplies and pipeline capacity to meet their customer requirements. However, it is possible for limited service disruptions to occur from time to time due to weather conditions, transportation constraints and other events. As a result of these factors, supplies of natural gas may become unavailable from time to time, or prices may increase rapidly in response to temporary supply constraints or other factors.

CenterPoint Energy’s and CERC’s Natural Gas has AMAs associated with their utility distribution service in Arkansas, Louisiana and Oklahoma with the Energy Services Disposal Group and in Arkansas, Indiana, Louisiana, Mississippi and Texas with other third parties. The AMAs have varying terms, the longest of which expires in 2025. Pursuant to the provisions of the agreements, CenterPoint Energy’s and CERC’s Natural Gas either sells natural gas to the asset manager and agrees to repurchase an equivalent amount of natural gas throughout the year at the same cost, or simply purchases its full natural gas requirements at each delivery point from the asset manager. Generally, AMAs are contracts between CenterPoint Energy’s and CERC’s Natural Gas and an asset manager that are intended to transfer the working capital obligation and maximize the utilization of the assets. In these agreements, CenterPoint Energy’s and CERC’s Natural Gas agrees to release transportation and storage capacity to other parties to manage natural gas storage, supply and delivery arrangements for CenterPoint Energy’s and CERC’s Natural Gas and to use the released capacity for other purposes when it is not needed for CenterPoint Energy’s and CERC’s Natural Gas. CenterPoint Energy’s and CERC’s Natural Gas may receive compensation from the asset manager through payments made over the life of the AMAs. CenterPoint Energy’s and CERC’s Natural Gas has an obligation to

For information regarding the proposed sale of certain Natural Gas businesses located in Arkansas and Oklahoma, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Significant Events — Business Review and Evaluation Committee” in Item 7 of Part II of this report.

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

CenterPoint Energy’s Midstream Investments reportable segment consists of its equity method investment in Enable. Enable is a publicly traded MLP, jointly controlled by CenterPoint Energy (indirectly through CNP Midstream) and OGE as of December 31, 2020. 

On September 4, 2018, CERC completed the Internal Spin of its equity investment in Enable, consisting of Enable common units and its interests in Enable GP, to CenterPoint Energy. For further discussion of the Internal Spin, see Note 11 to the consolidated financial statements.

Enable’s gathering and processing systems compete with gatherers and processors of all types and sizes, including those affiliated with various producers, other major pipeline companies and various independent midstream entities. Competition for crude oil, condensate, produced water and extracted NGL services also includes trucking and railroad transportation companies. In the process of selling NGLs, Enable competes against other natural gas processors extracting and selling NGLs. Enable’s primary competitors are other midstream companies who are active in the regions where it operates. Enable’s management views competition for its gathering and processing systems as a function of rates, terms of service, flexibility and reliability.

Enable’s interstate and intrastate pipelines compete with a variety of other interstate and intrastate pipelines across its operating areas in providing transportation and storage services. Enable’s management views the principal elements of competition among pipelines as rates, terms of service, flexibility and reliability of service. For natural gas transportation and storage, rates include both fees for services and retained fuel.

For information related to CenterPoint Energy’s equity method investment in Enable, see Note 2(c) and Note 11 to the consolidated financial statements.

For information relating to the recently announced Enable Merger, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Significant Events — Enable Merger Agreement” in Item 7 of Part II of this report and Note 22 to the consolidated financial statements.

CenterPoint Energy’s Corporate and Other consists of energy performance contracting and sustainable infrastructure services, such as renewables, distributed generation and combined heat and power projects, through ESG, and other corporate support operations that support CenterPoint Energy’s business operations. CenterPoint Energy’s Corporate and Other also includes office buildings and other real estate used for business operations.

The 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 and CenterPoint Energy’s investment in Enable as of December 31, 2020.

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 has authority to prohibit market manipulation in connection with FERC-regulated transactions, to conduct audits and investigations, and to impose significant civil penalties (up to approximately $1.3 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.

Indiana Electric is a “public utility” under the FPA and is subject to regulation by the FERC. The FERC regulates, among other things, 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. The FERC also has authority to impose significant civil penalties (up to approximately $1.3 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. 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 (Electric Entities). The ERO and the FERC have authority to (a) impose fines and other sanctions on Electric 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 and its consolidated subsidiaries are subject to reporting and accounting requirements and are required to maintain certain books and records and make them available for review by the FERC and state regulatory authorities in certain circumstances.

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

Houston Electric conducts its operations pursuant to a certificate of convenience and necessity issued by the PUCT that covers its present service area and facilities. The PUCT and certain municipalities have the authority to set the rates and terms of service provided by Houston Electric under cost-of-service rate regulation. Houston Electric holds non-exclusive franchises from certain incorporated municipalities in its service territory. In exchange for payment of fees, these franchises give Houston Electric the right to use the streets and public rights-of-way of these municipalities to construct, operate and maintain its transmission and distribution system and to use that system to conduct its electric delivery business and for other purposes that the franchises permit. The terms of the franchises, with various expiration dates, typically range from 30 to 40 years.

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 same rates and other charges for transmission and distribution services. This regulated delivery charge includes the transmission and distribution rate (which includes municipal franchise fees), a distribution recovery mechanism for recovery of incremental distribution-invested capital above that which is already reflected in the 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 relating to Hurricane Ike. Transmission rates charged to distribution companies are based on amounts of energy transmitted under “postage stamp” rates that do not vary with the distance the energy is being transmitted. All distribution companies in ERCOT pay Houston Electric the same rates and other charges for transmission services.

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

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

Indiana Electric owns and operates 1,000 MW of coal-fired generation, 163 MW of gas-fired generation and 4 MW of solar generation. Indiana Electric’s newest solar array, which was approved by the IURC in 2018, consists of approximately 150,000 solar panels distributed across 300 acres along Indiana State Road 545 between Troy and New Boston, Indiana. Construction of the 50 MW universal solar array was nearing completion at the end of 2020, and the project was placed in service for southwestern Indiana electric customers in early 2021. Indiana Electric also is party to two purchase power agreements, entitling it to the delivery of up to 80 MW of electricity produced by wind turbines. 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, DSMA, ECA, FAC, MCRA, RCRA Mechanism and TDSIC. 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. Operation 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.

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, although franchises in Arkansas are perpetual. CenterPoint Energy’s and CERC’s Natural Gas expects to be able to renew expiring franchises. In most cases, franchises to provide natural gas utility services are not exclusive.

Substantially all of CenterPoint Energy’s and CERC’s Natural Gas is subject to cost-of-service rate regulation by the relevant state public utility commissions and, in Texas, by those municipalities that have retained original jurisdiction. In certain of the jurisdictions in which they operate, CenterPoint Energy’s and CERC’s Natural Gas has annual rate adjustment mechanisms that provide for changes in rates dependent upon certain changes in invested capital, earned returns on equity or actual margins realized.

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

We 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. There are no self-enacting portions of this act that impact our assets.

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. However, because the PSR Amendments have not yet gone into effect, the Biden administration may review the PSR Amendments and potentially take steps to revise or revoke them. It is uncertain whether the PSR Amendments will go into effect as finalized and what effects the PSR Amendments may have on our operations.

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 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 incurred. Implementation by PHMSA of the PIPES Act, acts reauthorizing PHMSA or other future acts may result in other regulations or the reinterpretation of existing regulations that could impact compliance costs. In addition, CenterPoint Energy and CERC may be subject to the DOT’s enforcement actions and penalties if they fail to comply with pipeline regulations.

 

Federal, state, and local regulation of pipeline gathering and transportation services may affect certain aspects of Enable’s business and the market for its products and services, as discussed below.

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

The EPAct of 2005 amended the NGA to (i) prohibit market manipulation by any entity; (ii) direct the FERC to facilitate market transparency in the market for the sale or transportation of physical natural gas in interstate commerce; and (iii) significantly increase the penalties for violations of the NGA, the NGPA and FERC rules, regulations or orders thereunder. The anti-manipulation rules apply to interstate gas pipelines and storage companies and intrastate gas pipelines and storage companies that provide interstate services, such as Section 311 service, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction. The anti-manipulation rules do not apply to activities that relate only to intrastate or other non-jurisdictional transactions. As a result of the EPAct of 2005, the FERC has the authority to impose civil penalties for violations of these statutes and FERC rules, regulations and orders, up to approximately $1.3 million per day, per violation.

Intrastate natural gas transportation is largely regulated by the state in which the transportation takes place. 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 “—Market Behavior Rules; Posting and Reporting Requirements” above.

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 natural gas 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 natural gas 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 natural gas 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 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, then the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by FERC under the NGA or the NGPA.

States may regulate gathering pipelines. State regulation of natural gas gathering facilities generally includes various safety, environmental and, in some circumstances, anti-discrimination requirements, and in some instances complaint-based rate regulation. Enable’s natural gas 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 natural gas 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. CenterPoint Energy 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.

Enable’s crude oil gathering systems in the Williston Basin transport crude oil in interstate commerce. Crude oil gathering pipelines that transport crude oil in interstate commerce may be regulated as common carriers 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 confer any undue

Enable’s crude oil and condensate gathering system in the Anadarko Basin is located in Oklahoma and is subject to limited regulation by the OCC. Crude oil and condensate gathering systems are common carriers under Oklahoma law and are prohibited from unjust or unlawful discrimination in favor of one customer over another. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. Enable’s crude oil and condensate gathering results of operations and cash flows 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 pipeline facilities are subject to regulation under federal pipeline safety statutes and comparable state statutes. Federal pipeline safety statutes include the NGPSA, which provides for safety requirements in the design, construction, operation and maintenance of natural gas pipeline facilities, and the HLPSA, which provides for safety requirements for the design, construction, operation and maintenance of hazardous liquids pipelines facilities, including NGL and crude oil pipelines. Enable is also regulated under federal pipeline safety statutes by DOT through PHMSA. PHMSA sets and enforces pipeline safety regulations and standards. PHMSA’s enforcement authority includes the ability to assess civil penalties for violations of pipeline safety regulations. Enable incurs significant costs in complying with federal and state pipeline safety laws and regulations and otherwise administering its pipeline safety program.

The following discussion is based on environmental matters in the Registrants’ businesses as of December 31, 2020. 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 generation systems and the facilities that support these systems, the Registrants must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact the Registrants’ business activities in many ways, including, but not limited to:

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

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.

Increasingly, environmental regulation has 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 currently anticipated. The

Based on current regulatory requirements and interpretations, the Registrants do not believe that compliance with federal, state or local environmental laws and regulations will have a material adverse effect on their business, financial position, results of operations or cash flows. In addition, the Registrants believe that their current environmental remediation activities will not materially interrupt or diminish their operational ability. The Registrants cannot assure you 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 them to incur significant costs. The following is a discussion of material current environmental and safety issues, laws and regulations that relate to the Registrants’ operations. The Registrants believe that they are in substantial compliance with these environmental laws and regulations.

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 of the proposals would require industrial sources to meet stringent new standards that would require substantial reductions in 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. One such rule, the ACE Rule, which was finalized by the EPA in 2019, would have required states to establish heat rate performance standards for steam electric generating facilities. However, on January 19, 2021, the U.S. District Court of Appeals for the District of Columbia struck down the ACE Rule. 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. Shortly after taking office in January 2021, President Biden issued a series of executive orders designed to address climate change. President Biden has also signed an executive order requiring agencies to review environmental actions taken by the Trump administration, which would have included the ACE Rule, and the Biden administration has issued a memorandum to departments and agencies to refrain from proposing or issuing rules until a departmental or agency head appointed or designated by the Biden administration has reviewed and approved the rule. Reentry into the Paris Agreement and President Biden’s executive orders may result in the development of additional regulations or changes to existing regulations.

Houston Electric, in contrast to some electric utilities, does not generate electricity and thus is not directly exposed to the risk of high capital costs and regulatory uncertainties that face electric utilities that burn fossil fuels to generate electricity. Nevertheless, CenterPoint Energy’s and Houston Electric’s revenues could be adversely affected to the extent any resulting regulatory action has the effect of reducing consumption of electricity by ultimate consumers within Houston Electric’s service territory. 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. Conversely, regulatory actions that effectively promote the consumption of natural gas because of its lower emissions characteristics would be expected to beneficially affect CenterPoint Energy and CERC and their natural gas-related businesses. At this point in time, however, it would be speculative to try to quantify the magnitude of the impacts from possible new regulatory actions related to GHG emissions, either positive or negative, on the Registrants’ businesses. On March 1, 2020, CenterPoint Energy announced corporate carbon emission goals, which are expected to be used to guide Indiana Electric’s transition to a low carbon fleet and position Indiana Electric to comply with anticipated regulatory requirements to further reduce GHG emissions from its electric fleet.

To the extent climate changes may occur and such climate changes result in warmer temperatures in the Registrants’ or Enable’s service territories, financial results from the Registrants’ and Enable’s businesses could be adversely impacted. For example, CenterPoint Energy’s and CERC’s Natural Gas could be adversely affected through lower natural gas sales and Enable’s natural gas gathering, processing and transportation and crude oil gathering businesses could experience lower revenues. 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 for cooling. Another possible result of climate change is more frequent and more severe weather events, such as hurricanes, tornadoes and flooding. Since many of the Registrants’ facilities are located along or near the Gulf Coast, increased or more severe hurricanes or tornadoes could increase costs to repair damaged facilities and restore service to customers. 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.

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. The 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. The 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 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 the Registrants’ pipelines or facilities could result in fines or penalties as well as significant remedial obligations.

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. The Trump administration signaled its intent to repeal and replace the Obama-era rules. In accordance with this intent, the EPA promulgated a rule in early 2018 that postponed the effectiveness of the Obama-era rules until 2020. Thereafter, the EPA proposed a new set of rules that would narrow the Clean Water Act’s jurisdiction, which were finalized on April 21, 2020. Environmental stakeholders and certain states have filed challenges to the new rule. Shortly after taking office in January 2021, President Biden signed an executive order requiring agencies to review environmental actions taken by the Trump administration, including the April 2020 rule, but the nature and extent of any revisions to these rules that may be sought is uncertain at this time. The potential impact of the litigation or further revisions to the “waters of the United States” regulations on the Registrants’ business, liabilities, compliance obligations or profits and revenues is uncertain at this time.

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.

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 2021-2022.

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

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 is required to cease disposal of new ash in the ponds and commence closure of the ponds by April 11, 2021. Indiana Electric plans to seek 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. 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 16(e) to the consolidated financial statements.

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 the Registrants’ ordinary operations they 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, the 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.

For information about preexisting environmental matters, please see Note 16(e) to the consolidated financial statements.

CenterPoint Energy believes its employees are critical components to safely delivering electricity and natural gas across its service territories and seeks to create a diverse, 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 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 employees by Registrant and reportable segment as of December 31, 2020:

For information about the status of collective bargaining agreements, see Note 8(j) to the consolidated financial statements.

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

CenterPoint Energy derives all of its operating income from, and holds all of its assets through, its subsidiaries, including its interests in Enable. As a result, CenterPoint Energy depends on the performance of and distributions from its subsidiaries and Enable to meet its payment obligations and to pay dividends on its common and preferred stock. In general, CenterPoint Energy’s subsidiaries are separate and distinct legal entities and have no obligation to provide it with funds for its 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 subsidiaries’ and Enable’s ability to make payments or other distributions to CenterPoint Energy, and its subsidiaries or Enable could agree to contractual restrictions on their ability to make payments or other distributions. Further, Houston Electric has agreed to certain “ring-fencing” measures to increase its financial separateness from CenterPoint Energy. 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 ring-fencing measures impacting CenterPoint Energy’s ability to receive dividends from Houston Electric could materially adversely affect CenterPoint Energy’s cash flows, credit quality, financial condition and results of operations.

CenterPoint Energy’s right to receive any assets of any subsidiary, and therefore the right of its creditors to participate in those assets, will be 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 be effectively subordinated to any security interest in the assets of that subsidiary and any indebtedness of the subsidiary senior to that held by CenterPoint Energy.

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, (iii) distributions from CenterPoint Energy’s interests in Enable and (iv) 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. As of December 31, 2020, CenterPoint Energy had $13.4 billion of outstanding indebtedness on a consolidated basis, which includes $747 million of non-recourse Securitization Bonds. For information on outstanding indebtedness of Houston Electric and CERC as well as maturities through 2025, see Note 14 to the consolidated financial statements. Our future financing activities may be significantly affected by, among other things:

In addition, our future financing activities may also be impacted by our ability to consummate the proposed sale of our Natural Gas businesses in Arkansas and Oklahoma. For further information on the proposed sale, see “— 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” below. With respect to impacts related to our investment in Enable, see Note 22 to the consolidated financial statements for further information on the recently announced Enable Merger.

The Registrants’ current credit ratings and any changes in credit ratings in 2020 and to date in 2021 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 lowered or withdrawn entirely by a rating agency. The Registrants note that 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 a material adverse impact on their ability to access capital on acceptable terms.

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. 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, reducing the carrying value of the reporting unit to its fair value as of March 31, 2020. See Note 6 to the consolidated financial statements for further information. For investments CenterPoint Energy accounts for under the equity 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. CenterPoint Energy identified and recorded an impairment during the year ended December 31, 2020 based on the severity of the decline in Enable’s common unit price during the three months ended March 31, 2020 due to the macroeconomic conditions related in part to the COVID-19 pandemic, combined with Enable’s announcement on April 1, 2020 to reduce its quarterly distributions per common unit by 50%, and the market outlook indicating excess supply of crude oil and natural gas and continued depressed crude oil and natural gas prices impacting the midstream oil and gas industry. For further information regarding CenterPoint Energy’s impairment of its equity investment in Enable, please see Notes 10 and 11 to the consolidated financial statements. Should the annual goodwill impairment test or another periodic impairment test or an observable transaction, including for the Series A Preferred Unit investment, 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 sustained or severe decline in Enable’s common unit price could result in CenterPoint Energy recording impairment charges again in the future. A non-cash impairment charge or fair value adjustment could materially adversely impact our results of operations and financial condition.

CenterPoint Energy has approximately $828 million principal amount of ZENS outstanding as of December 31, 2020. 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 ($56 million in the aggregate, or $3.97 per ZENS, as of December 31, 2020) 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, 2020, deferred taxes of approximately $471 million would have been payable in 2020, based on 2020 tax rates in effect. In addition, if all the shares of ZENS-Related Securities had been sold on December 31, 2020 to fund the aggregate redemption amount, capital gains taxes of approximately $159 million would have been payable in 2020. 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 or the market for the ZENS were to become illiquid, or for some other reason. While funds for the payment of cash upon exchange of ZENS could be obtained from the sale of the shares of ZENS-Related Securities that CenterPoint Energy owns or from other sources, ZENS exchanges result in a cash outflow

CenterPoint Energy has issued 800,000 shares of Series A Preferred Stock and 19,550,000 depositary shares, each representing a 1/20th interest in a share of CenterPoint Energy’s Series B Preferred Stock, which is expected to convert into Common Stock on September 1, 2021. CenterPoint Energy has also issued 725,000 shares of Series C Preferred Stock of which 625,000 shares remain outstanding. The Series C Preferred Stock are expected to convert to Common Stock on or around May 7, 2021. Any future payments of cash dividends, and the amount of any cash dividends CenterPoint Energy pays, on its Series A Preferred Stock, Series B Preferred Stock and Series C Preferred Stock will depend on, among other things, its financial condition, capital requirements and results of operations and the ability of our subsidiaries and Enable 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, Series B Preferred Stock and Series C Preferred Stock when due could materially adversely impact our ability to access capital on acceptable terms and would likely have a material adverse impact on the market price of the Series A Preferred Stock, the Series B Preferred Stock, Common Stock and CenterPoint Energy’s debt securities and would prohibit CenterPoint Energy, under the terms of the Series A Preferred Stock and Series B 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 and the Series B Preferred Stock.

Further, the terms of the Series A Preferred Stock and the Series B 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 or its Series B 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 rates that Houston Electric and Indiana Electric are allowed to charge may not match their costs at any given time, a situation referred to as “regulatory lag.” For Houston Electric and Indiana Electric, several interim rate adjustment mechanisms have been implemented to reduce the effects of regulatory lag (for example, DCRF, TCOS, TDSIC, DSMA and RCRA Mechanism), although certain of these mechanisms do not provide for recovery of operations and maintenance expenses. These adjustment mechanisms are subject to the applicable regulatory body’s approval and are subject to limitations that may reduce Houston Electric’s and Indiana Electric’s ability to adjust rates. For further information on rate case proceedings and interim rate adjustment mechanisms, 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. See also “—The February 2021 Winter Storm Event has caused severe disruptions to our customers and our markets in certain of our jurisdictions and could have a material adverse impact to our financial condition, results of operations, cash flows and liquidity” below for further information.

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

Houston Electric transmits and distributes to customers of REPs electric power that the REPs obtain from power generation facilities owned by third parties. Houston Electric does not own or operate any power generation facilities. In February 2021, the Texas electric system experienced an unprecedented power shortage due to extreme winter weather conditions. The state’s power generation fell short of demand, resulting in significant electricity outages across Texas, including in Houston Electric’s service territory. See Note 22 to the consolidated financial statements for further information on the February 2021 Winter Storm Event. If power generation is disrupted or if power generation capacity is inadequate or if ERCOT issues directives to TDUs (such as Houston Electric) to implement controlled outages, both of which recently occurred during the February 2021 Winter Weather Event, Houston Electric’s sales of transmission and distribution services may be diminished or interrupted, and its reputation, results of operations, financial condition and cash flows could be adversely affected. See also “—The February 2021 Winter Storm Event has caused severe disruptions to our customers and our markets in certain of our jurisdictions and

Houston Electric’s receivables from the distribution of electricity are collected from REPs that supply the electricity Houston Electric distributes to their customers. As of December 31, 2020, Houston Electric did business with approximately 64 REPs. Adverse economic conditions, including the impact of COVID-19, the February 2021 Winter Storm Event, structural problems in the market served by ERCOT or financial difficulties of one or more REPs could impair the ability of these REPs to pay for Houston Electric’s services or could cause them to delay such payments. Houston Electric depends on these REPs to remit payments on a timely basis. Applicable regulatory provisions require that customers be shifted to another REP or a provider of last resort if a REP cannot make timely payments. Applicable PUCT regulations significantly limit the extent to which Houston Electric can apply normal commercial terms or otherwise seek credit protection from firms desiring to provide retail electric service in its service territory, and Houston Electric thus remains at risk for payments related to services provided prior to the shift to another REP or the provider of last resort. A significant portion of Houston Electric’s billed receivables from REPs are from affiliates of NRG and Vistra Energy Corp. Houston Electric’s aggregate billed receivables balance from REPs as of December 31, 2020 was $210 million. Approximately 31% and 16% of this amount was owed by affiliates of NRG and Vistra Energy Corp., respectively. Any delay or default in payment by REPs could adversely affect Houston Electric’s cash flows, financial condition and results of operations. If a REP were unable to meet its obligations, it could consider, among various options, restructuring under the bankruptcy laws, in which event such REP might seek to avoid honoring its obligations, and claims might be made by creditors involving payments Houston Electric had received from such REP.

Indiana requires each electric utility to perform and submit an IRP every three years, unless extended, to the IURC 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 on a periodic basis. Indiana Electric’s 2016 IRP modeling projected that the lowest cost and least risk generation portfolio to serve customers over the next 20 years involve retirement of a significant portion of its current generating fleet and replacing that generation capacity with other resources. Implementation of Indiana Electric’s IRP will likely require recovery of new capital investments, as well as costs of retiring the current generation fleet, including any remaining unrecovered costs of retired assets. In February 2018, as part of its electric generation transition plan, Indiana Electric received approval from the IURC to construct a 50 MW universal solar array and the plan to retrofit its largest, most efficient coal-fired generation unit (Culley Unit 3). With respect to its 2019/2020 IRP submitted to the IURC in June 2020, Indiana Electric identified a preferred generation resource that includes the replacement of 730 MW of coal-fired generation facilities with a significant portion composed of renewables, including solar and wind, supported by dispatchable natural gas combustion turbines, including a pipeline to serve such natural gas generation, as well as storage. While the IURC does not approve or reject the IRP, the process involves the issuance of a staff report that provides comments on the IRP. Depending on comments received on the IRP, the filing of any future requests for generating facilities could be delayed. Further, certain legislative activities such as a prohibition on the construction of new generation assets in excess of a set MW capacity, similar to moratorium legislation introduced in 2019 and ultimately defeated, or other legislation restricting or delaying new generation could negatively affect Indiana Electric’s ability to construct new generation facilities and execution of its capital plan. Even if a generation project is approved, risks associated with the construction of any new generation exist, including 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 and cost overruns and the ability to meet capacity requirements. Further, there is no guarantee that the IURC will approve the requests included in any of Indiana Electric’s future filed petitions relating to its IRP. For further information on the IRP, 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.

Additionally, Indiana Electric’s generating facilities are subject to operational risks that could result in unscheduled plant outages, unanticipated operation and maintenance expenses, increased purchase power costs and inadvertent releases of coal ash and/or other contaminants with a significant environmental impact. These operational risks can arise from circumstances such as facility shutdowns or malfunctions due to equipment failure or operator error; interruption of fuel supply or increased prices of fuel as contracts expire; 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 business. Further, Indiana Electric currently relies on coal for substantially all of its generation capacity. Currently, its coal supply is purchased largely from a

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 the ERO to promulgate standards, under FERC oversight, for all owners, operators and users of the bulk power system. The FERC has approved the delegation by the NERC of authority for reliability in ERCOT to the Texas RE, a Texas non-profit corporation 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. In addition, if Houston Electric or Indiana Electric were to be found to be in noncompliance with applicable mandatory reliability standards, they could be subject to sanctions, including substantial monetary penalties.

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. Agencies and entities that may conduct or are conducting such inquiries, investigations and other reviews 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 around these discussions and whether any market structure or governance changes will result therefrom, but if any such reviews and reform efforts ultimately result in changes to how the Texas electric market is structured or regulated, such changes could have a material adverse impact on Houston Electric’s business, results of operations and financial condition. See “—The February 2021 Winter Storm Event has caused severe disruptions to our customers and our markets in certain of our jurisdictions and could have a material adverse impact to our financial condition, results of operations, cash flows and liquidity” below and Note 22 to the consolidated financial statements for further information.

Natural Gas’ rates are regulated by certain municipalities (in Texas only) and state commissions based on an analysis of Natural Gas’ 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 Natural Gas’ control. Natural Gas has pending, or anticipates the filing of, rate cases in Indiana and Minnesota during 2021. Natural Gas can make no assurance that these respective base rate proceedings will result in favorable adjustments to its rates, full cost recovery or approval of other requested items, including, among other things, capital structure and ROE. Moreover, these base rate proceedings could cause Natural Gas to recover its investments at rates below its requested level, below the national average for utilities or below recently approved levels for other utilities in those jurisdictions.

The rates that Natural Gas is allowed to charge may not match its costs at any given time, resulting in what is referred to as “regulatory lag.” Though several interim rate adjustment mechanisms have been approved by jurisdictional regulatory authorities and implemented by Natural Gas to reduce the effects of regulatory lag (for example, GRIP, FRP, CSIA and DRR), such adjustment mechanisms are subject to the applicable regulatory body’s approval, which we cannot assure would be

Natural Gas 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 Natural Gas’ costs or enable Natural Gas to earn an expected return. Changes to the interim adjustment mechanisms could result in an increase in regulatory lag or otherwise impact Natural Gas’ 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 Natural Gas and deny the full recovery of Natural Gas’ cost of service or the full recovery of incurred natural gas costs in rates. To the extent the regulatory process does not allow Natural Gas to make a full and timely recovery of appropriate costs, its results of operations, financial condition and cash flows could be adversely affected. For further information on rate case proceedings and interim rate adjustment mechanisms, 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.

Unlike CERC, Indiana Gas, SIGECO’s natural gas distribution business and VEDO must seek approval by the IURC and PUCO, as applicable, for long-term financing authority. This authority allows these utilities the flexibility to enter into various financing arrangements. In the event that the IURC or PUCO do not approve these utilities’ respective financing authorities, they may not be able to fully execute their financing plans and their respective financial conditions, results of operations and cash flows could be adversely affected.

Natural Gas depends on third-party service providers to maintain an adequate supply of natural gas and for available storage and intrastate and interstate pipeline capacity to satisfy its customers’ needs, all of which are critical to system reliability. Substantially all of Natural Gas’ natural gas supply is purchased from intrastate and interstate pipelines. If 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 Natural Gas’ requirements, the resulting decrease in natural gas supply in Natural Gas’ service territories could have a material adverse effect on its results of operations, cash flows and financial condition. Additionally, a significant disruption, whether through reduced intrastate and interstate pipeline transmission or storage capacity or other events affecting natural gas supply, including, but not limited to, operational failures, hurricanes, tornadoes, floods, severe winter weather conditions, acts of terrorism or cyberattacks or changes in legislative or regulatory requirements, could also adversely affect Natural Gas’ businesses. Further, to the extent that Natural Gas’ natural gas requirements cannot be met through access to or continued use of existing natural gas infrastructure or if additional infrastructure, including onshore and offshore exploration and production facilities, gathering and processing systems and pipeline and storage capacity is not constructed at a rate that satisfies demand, then Natural Gas’ operations could be negatively affected. For additional risks related to the February 2021 Winter Storm Event, see “—The February 2021 Winter Storm Event has caused severe disruptions to our customers and our markets in certain of our jurisdictions and could have a material adverse impact to our financial condition, results of operations, cash flows and liquidity” below and Note 22 to the consolidated condensed financial statements for further information.

Natural Gas is subject to risk associated with changes in the notional price of natural gas. Increases in natural gas prices might affect Natural Gas’ ability to collect balances due from customers and could create the potential for uncollectible accounts expense to exceed the recoverable levels built into tariff rates. In addition, a sustained period of high natural gas prices could (i) decrease demand for natural gas in the areas in which Natural Gas operates, thereby resulting in decreased sales and revenues and (ii) increase the risk that Natural Gas’ suppliers or customers fail or are unable to meet their obligations. An increase in natural gas prices would also increase working capital requirements by increasing the investment that must be made to maintain natural gas inventory levels. For additional risks related to the February 2021 Winter Storm Event, see “—The February 2021 Winter Storm Event has caused severe disruptions to our customers and our markets in certain of our jurisdictions and could have a material adverse impact to our financial condition, results of operations, cash flows and liquidity” below and Note 22 to the consolidated condensed financial statements for further information.

If CERC’s credit rating were to decline, it might be required to post cash 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 results of operations, financial condition and cash flows could be adversely affected. For additional risks related to the February 2021 Winter Storm Event, see “—The February 2021 Winter Storm Event has caused severe disruptions to our customers and our markets in certain of our jurisdictions and could have a material adverse impact to our financial condition, results of operations, cash flows and liquidity” below and Note 22 to the consolidated condensed financial statements for further information.

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 marketers also compete directly with Natural Gas for natural gas sales to end users. In addition, as a result of federal regulatory changes affecting interstate pipelines, natural gas marketers operating on these pipelines may be able to bypass Natural Gas’ facilities and market, sell and/or transport natural gas directly to commercial and industrial customers. Any reduction in the amount of natural gas delivered by Natural Gas as a result of competition with alternate energy sources may have an adverse impact on CERC’s results of operations, financial condition and cash flows.

ESG’s business results are dependent on a number of factors. The industry in which ESG operates is competitive and many of the contracts are subject to a bidding process. Should ESG 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 ESG operate could adversely impact operating results. Additionally, ESG’s business is subject to other risks including, but not limited to, the following: the discontinuation of the federal ESPC and UESC programs; the inability of customers to finance projects; failure to appropriately design, construct or operate projects; and cancellation of projects by customers or reductions in the scope of the projects.

In the normal course of business, ESG 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 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.

Our operations are subject to stringent and complex laws and regulations pertaining to the environment. As an owner or operator of natural gas pipelines, distribution systems and storage, steam electric generating facilities and electric transmission and distribution systems, and the facilities that support these systems, we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, including among others, restricting the use of fossil fuels through future climate legislation or regulation, limiting airborne emissions from generating facilities, restricting the way we manage wastes, including wastewater discharges and air emissions and requiring remedial action or monitoring to mitigate environmental actions caused by our operations or attributable to former

Furthermore, in March 2020, we established a goal to reduce carbon emissions directly attributable to our operations 70% from 2005 levels by 2035, and we announced a broad corporate initiative to achieve a net reduction of carbon emissions attributed to customer usage 20–30% from 2005 levels by 2040. Our ability to achieve these carbon emission reduction goals depends on various external factors, including supportive energy policies, alternative fuels programs, research and development efforts focused on low-carbon technologies such as carbon capture, customer participation in conservation and energy-efficiency programs and low natural gas prices. We expect to increase our renewable energy resources portfolio as part of our IRP process and to continue optimizing technology advancements to modernize our systems. Any negative opinions with respect to these goals or our environmental practices, including any inability to achieve, or a scaling back of, these goals developed by regulators, customers, investors or legislators could harm our reputation.

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 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. Also, certain cities in CenterPoint Energy’s Natural Gas operational footprint have adopted 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. Also, Minnesota cities may consider seeking legislative authority for the ability to enact voluntary enhanced energy standards for all development projects. Any such initiatives and legislation could adversely affect CenterPoint Energy’s results of operations.

In February 2021, certain of our jurisdictions experienced an extreme and unprecedented winter weather event that resulted in prolonged freezing temperatures, which impacted, and may continue to impact, our businesses.

In addition to the risks discussed in this risk factor, for further information on risks related to:

CenterPoint Energy continues to integrate certain aspects of CenterPoint Energy’s and Vectren’s businesses. The integration of technology systems and processes that CenterPoint Energy uses to plan and report financial information, manage work, monitor systems, respond to outages and perform other critical functions has been, and continues to be, a complex, costly and time consuming process, which is expected to be completed in 2021. CenterPoint Energy may experience delays, cost-overruns or other issues affecting the successful completion of the integration of these technology systems and other related processes. The failure to timely, efficiently and cost-effectively complete the integration could adversely affect CenterPoint Energy’s results of operations and cash flows.

In connection with the integration of such technology systems and processes, CenterPoint Energy must also successfully design and operate its systems of internal controls to continue to accurately provide reliable financial reports, including reporting of its financial condition, results of operations or cash flows, effectively prevent fraud and operate successfully as a public company. If CenterPoint Energy’s efforts to maintain an effective system of internal controls throughout the integration of its technology systems are not successful, it is unable to maintain adequate controls over its financial reporting and processes in the future or it is unable to comply with its obligations under Section 404 of the Sarbanes-Oxley Act of 2002, CenterPoint Energy could be harmed or it may fail to meet its reporting obligations. Ineffective internal controls also could cause investors to lose confidence in CenterPoint Energy’s reported financial information, which would likely have a negative effect on, among other things, the trading prices of its securities.

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. These risks include, but are not limited to, the following:

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

A significant portion of Houston Electric’s revenues is derived from rates that it collects from each REP based on the amount of electricity it delivers on behalf of such REP. Similarly, Indiana Electric’s revenues are derived from rates it charges its customers to provide electricity. Natural Gas’ revenues are primarily derived from natural gas sales. Consequently, 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 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 our weather hedges, see Note 9(a) to the consolidated financial statements. For additional risks related to the February 2021 Winter Storm Event, see “—The February 2021 Winter Storm Event has caused severe disruptions to our customers and our markets in certain of our jurisdictions and could have a material adverse impact to our financial condition, results of operations, cash flows and liquidity” below and Note 22 to the consolidated condensed financial statements for further information.

A changing climate creates uncertainty and could result in broad changes, both physical and financial in nature, to our service territories. If climate changes occur that result in warmer temperatures in our service territories, financial results from our businesses could be adversely impacted. For example, Natural Gas could be adversely affected through lower natural gas usage. Another possible result of climate change is more frequent and more severe weather events, such as hurricanes, tornadoes or severe winter weather conditions, including ice storms. Since certain 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. For example, in 2020, eight named storms occurred along the Gulf Coast. Of these eight storms, we experienced four named hurricanes in our service territories, which impacted our Natural Gas facilities. Our electric and Natural Gas operations in our services territories were impacted due to the February 2021 Winter Storm Event. For further information on the February 2021 Winter Storm Event, see Note 22 to the consolidated financial statements and “—The February 2021 Winter Storm Event has caused severe disruptions to our customers and our markets in certain of our jurisdictions and could have a material adverse impact to our financial condition, results of operations, cash flows and liquidity” above. When we cannot deliver electricity or natural gas to customers or our customers cannot receive our services, our financial results can be impacted by lost revenues, and we generally must seek approval from regulators to recover restoration costs. To the extent we are unable to recover those costs, or if higher rates resulting from our recovery of such costs result in reduced demand for our services, our future financial results may be adversely impacted. Any such decreased energy use may also require us to retire current infrastructure that is no longer needed. Further, we may be subject to climate change lawsuits, which could result in substantial penalties or damages.

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.  Failure to achieve timely and full recovery of these expenses 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. 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 that 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 results of operations, financial condition and cash flows.

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. Additionally, 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, operating results, financial condition and cash flows could be materially and adversely affected.

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, 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. Additionally, the significant decline in energy and commodity prices that occurred during 2020, if sustained into 2021, could cause the rate of economic, employment and/or population growth in certain of our service territories to decline. In particular, Houston, Texas has a higher percentage of employment tied to the energy sector relative to other regions of the country. 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. As such, sustained low energy and commodity prices could have an adverse impact on our financial condition, results of operations, cash flows and liquidity. 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.

Enable has historically been 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

Enable is expected to pay a distribution of $0.625 per Enable Series A Preferred Unit, or $2.50 per Enable Series A Preferred Unit on an annualized basis, until February 17, 2021. Thereafter, Enable is expected to pay a distribution on the Enable Series A Preferred Units with an annual rate equal to three-month LIBOR plus 8.5%. Distributions on each Enable Series A Preferred Unit are not mandatory and are non-cumulative in the event distributions are not declared on the Enable Series A Preferred Units. Additionally, distributions on the Enable Series A Preferred Units reduce the amount of available cash Enable has to pay distributions on its common units. The amount of cash Enable can distribute on its common units and the Enable Series A Preferred Units will principally depend upon the amount of cash it generates from its operations, which will fluctuate from quarter to quarter based on, among other things, the fees and gross margins it realizes with respect to the volume of natural gas, NGLs and crude oil that it handles and the prices of, levels of production of, and demand for natural gas, NGLs and crude oil. Please refer to Enable’s operational, regulatory and financial risks and other factors set forth in its SEC filings that may have a material impact on its performance and cash distributions, and, hence, the value of CenterPoint Energy’s interests in Enable.

We 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 businesses, which includes, among other things, (i) managing operations and other business processes and (ii) protecting sensitive information maintained in the normal

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. 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 cyberattacks and unauthorized access. We are not fully insured against all cybersecurity risks, any of which could adversely affect our reputation and could have a material adverse effect on our results of operations, financial condition and/or cash flows. As domestic and global cyber threats are on-going and increasing in sophistication, magnitude and frequency, our critical energy infrastructure may be targets of state-sponsored attacks, terrorist activities or otherwise that could disrupt our respective business operations. Furthermore, experts have observed an increase in the volume and the sophistication of cyberattacks since the beginning of the COVID-19 pandemic, which could lead to additional disruptions. For information about our cybersecurity risks related to COVID-19, please see “—We face risks related to COVID-19 and other health epidemics and outbreaks, including economic, regulatory, legal, workforce and cyber security risks, which could adversely impact our financial condition, results of operations, cash flows and liquidity” below. Any such disruptions could result in significant costs to repair damaged facilities, restore service and implement increased security measures, which could have a material adverse effect on our results of operations, financial condition and/or cash flows.

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 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. 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 laws, we may incur significant liabilities and penalties as a result.

We currently have insurance in place, such as general liability and property insurance, 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 results of operations, financial condition and cash flows. Costs, damages and other liabilities related to recent events and incidents that affected other utilities, such as wildfires and explosions, among other things, have exceeded or could exceed such utilities’ insurance coverage. Further, as a result of these recent events and incidents, the marketplace for insurance coverage may be unavailable or limited in capacity or any such available coverage may be deemed by us to be cost prohibitive under current conditions. Any such coverage, if available, may not be eligible for recovery, whether in full or in part, by us through the rates charged by our utility businesses.

In common with other companies in its line of business that serve coastal regions, Houston Electric does not have insurance covering its transmission and distribution system, other than substations, because Houston Electric believes it to be cost prohibitive and 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 regulated rates or otherwise. In the future, any such recovery may not be granted. Therefore, Houston Electric may not be able to restore any loss of, or damage to, any of its transmission and distribution properties without negative impact on its results of operations, financial condition and cash flows.

The COVID-19 pandemic is a rapidly evolving situation that is adversely affecting current global economic activities and conditions. An extended slowdown of economic growth, decreased demand for commodities and/or material changes in governmental or regulatory policy in the United States has resulted in, and could continue to result in, lower growth, including customer growth, and reduced demand for and usage of electricity and natural gas in our service territories as customer facilities close, remain closed or potentially close again. We have experienced reduced demand and usage among our electric and natural gas commercial and industrial customers, as well as a decrease in revenues from disconnections and reconnections due to the disconnect moratoriums across our service territories due to COVID-19, which have either expired or may expire during the second quarter of 2021 in certain of the Registrants’ service territories. The ability of our customers, contractors and suppliers to meet their obligations to us, including payment obligations, has also been negatively affected under the current economic conditions. As a result of the disconnect moratoriums across our Natural Gas service territories and other payment deferrals or arrangements, days outstanding on receivables and uncollectible accounts have increased, resulting in an increase to allowance for credit losses. To the extent these conditions in our service territories persist, our bad debt expense from uncollectible accounts could continue to increase, negatively impacting our financial condition, results of operations and cash flows. REPs could encounter financial difficulties, including bankruptcies, which could impair their ability to pay for Houston Electric’s services or could cause them to delay such payments, adversely affecting Houston Electric’s cash flows and liquidity. Additionally, our state and local regulatory agencies, in response to a federal mandate or otherwise, could impose restrictions on the rates we charge to provide our services, including the inability to implement approved rates, or delay actions with respect to our rate cases and filings. The COVID-19 pandemic may affect our ability to timely satisfy regulatory requirements such as recordkeeping and/or timely reporting requirements. For further information on COVID-19 regulatory matters, please see Note 7 to the consolidated financial statements, which information is incorporated herein by reference.

With respect to our supply chain, while we have not experienced significant disruptions or challenges from the COVID-19 pandemic, to the extent we experience such disruptions in our supply chain that limit our ability to obtain materials and equipment necessary for our businesses, whether through delayed order fulfillment, limited production or unavailability due to COVID-19, we may be unable to perform our operations timely or as anticipated, which could result in service or construction delays or increased costs. Furthermore, in the event key officers or a substantial portion of our workforce were to be impacted by COVID-19 for an extended period of time, we may face challenges with respect to our services or operations and we may not be able to execute our capital plan as anticipated. There is considerable uncertainty regarding the extent to which COVID-19 will continue to spread, even with the availability of a vaccine therefor, and the extent and duration of governmental and other measures implemented to try to slow the spread of COVID-19, such as large-scale travel bans and restrictions, border closures, quarantines, shelter-in-place orders and business and government shutdowns. Restrictions of this nature have caused, and may continue to cause, us, our suppliers and other business counterparties to experience operational delays, shortages of employees, facility shutdowns or business closures. We have modified certain business and workforce practices (including those related to employee travel, employee work locations and participation in meetings, events and conferences) to conform to government restrictions and best practices encouraged by governmental and regulatory authorities. However, the quarantine of personnel or the inability to access our facilities or customer sites could adversely affect our operations. While certain of our personnel have been, and may continue to be, quarantined, our operations and corporate functions have not been adversely affected to date. As of the date of this Form 10-K, we have increased the permitted occupancy of certain of our offices and facilities, with the rest of our office-based personnel continuing to work remotely under alternate work arrangements. Where we must maintain a presence in the field, we have adjusted our operational protocols to minimize exposure and risk to our field personnel, customers and the communities we serve, including, among other things, modifying our work schedules and reporting locations, delaying certain work types, such as maintenance and capital projects, and adjusting project scope and scale to adhere to safety protocols, while continuing to maintain the work activities necessary for safe and reliable service to our customers with increased safety precautions, but we cannot assure that such adjustments and precautions will be sufficient to minimize exposure to and risk from COVID-19. Also, we have a limited number of highly skilled employees for some of our operations. If a large proportion of our employees in those critical positions were to contract COVID-19 at the same time, we would rely upon our business continuity plans in an effort to continue operations at our facilities, but there is no certainty that

Experts have observed an increase in the volume and the sophistication of cyberattacks since the beginning of the COVID-19 pandemic. Any technology system breaches and/or data privacy incidents could disrupt our operations or result in the loss or exposure of confidential or sensitive customer, employee or company information and adversely affect our business, financial condition and results of operations. As many of our employees and third-party service providers work remotely in accordance with government mandates or guidelines, we face heightened cyber security and privacy risks related to unauthorized system access, aggressive social engineering tactics and adversaries attacking the information technology systems, network infrastructure, technology and facilities used to conduct our business. The increase in the remote working arrangements of our employees as a result of the COVID-19 pandemic has required enhancements and modifications to our information technology infrastructure (for example, virtual private network, or VPN, and remote collaboration systems), and any failures of these technologies, including third-party service providers, that facilitate working remotely could limit our ability to conduct our ordinary operations and expose us to increased risk or impact of a cyberattack.

We will continue to monitor developments affecting our employees, customers and operations. At this time, however, we cannot predict the extent or duration of the COVID-19 pandemic or its effects on national, state and local economies, including the impact on our ability to access capital markets, our supply chain, our business strategies and plans and our workforce, nor can we estimate the potential adverse impact from COVID-19 on our financial condition, results of operations, cash flows and liquidity.

We depend on senior executive officers and other key personnel. Our success depends on our ability to attract, effectively transition 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.

Our businesses are dependent on recruiting, retaining and motivating employees. 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 businesses, particularly the specialized skills and knowledge required to construct and operate generation facilities, a technology-enabled power grid and transmission and distribution facilities, among other facilities. If we are unable to successfully attract and retain an appropriately qualified workforce, our results of operations could be negatively affected.

Furthermore, the operations of our facilities depends on good labor relations with our employees, and several of our businesses have entered into and have in place collective bargaining agreements with different labor unions, comprising approximately 36% of our workforce. We have several separate bargaining units, each with a unique collective bargaining agreement described further in Note 8(j) to the consolidated financial statements, which information is incorporated herein by reference. The collective bargaining agreements with OPEIU Local 12 and Mankato related to Natural Gas employees in Minnesota are scheduled to expire in May 2021 and March 2021, respectively, and negotiations are currently in progress and expected to be completed before the May 2021 and March 2021 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 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 adverse effect on our businesses, results of operations and/or cash flows.

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 addition to affecting CenterPoint Energy’s funding requirements, these factors could adversely affect our results of operations, liquidity and financial position.

Our businesses are impacted by U.S. federal income tax policy. Under the Biden administration with the Senate and House of Representatives controlled by the Democratic Party, comprehensive 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 results of operations, financial conditions 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 results of operations, financial condition and cash flows.

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 our 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.

None.

The following discussion is based on the Registrants’ businesses as of December 31, 2020.

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

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:

For information related to debt outstanding under the Mortgage and General Mortgage, see Note 14 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:

As of December 31, 2020, CenterPoint Energy’s and CERC’s Natural Gas owned approximately 99,000 and 77,000 linear miles of natural gas distribution and transmission mains, respectively, varying in size from one-half inch to 24 inches in diameter. CenterPoint Energy’s Natural Gas in Indiana and Ohio includes approximately 22,000 miles of distribution and transmission mains, all of which are located in Indiana and Ohio except for pipeline facilities extending from points in northern Kentucky to points in southern Indiana so that gas may be transported to Indiana and sold or transported to customers in Indiana. Generally, in each of the cities, towns and rural areas served by CenterPoint Energy’s and CERC’s Natural Gas, they own the underground gas mains and service lines, metering and regulating equipment located on customers’ premises and the district regulating equipment necessary for pressure maintenance. With a few exceptions, the measuring stations at which CenterPoint Energy’s and CERC’s Natural Gas receives gas are owned, operated and maintained by others, and their distribution facilities begin at the outlet of the measuring equipment. These facilities, including odorizing equipment, are usually located on land owned by suppliers.

As of December 31, 2020, CEIP owned and operated over 264 miles of intrastate pipeline in Louisiana, Texas and Oklahoma.

For a discussion of material legal and regulatory proceedings affecting the Registrants as of December 31, 2020, please read “Business — Regulation” and “Business — Environmental Matters” in Item 1 of this report, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Regulatory Matters” in Item 7 of this report and Note 16(e) to the consolidated financial statements, which information is incorporated herein by reference.

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

As of February 22, 2021, CenterPoint Energy’s common stock was held by approximately 26,409 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 results of operations and financial condition, 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 13 to the consolidated financial statements.

During the quarter ended December 31, 2020, 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.

As of February 22, 2021, all of Houston Electric’s 1,000 outstanding common shares were held by Utility Holding, LLC, a wholly-owned subsidiary of CenterPoint Energy.

As of February 22, 2021, 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.

Not applicable.

CenterPoint Energy, Inc. is a public utility holding company and owns interests in Enable. 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 and discontinued operations, please read Note 1 to the consolidated financial statements.

Houston Electric is an indirect, wholly-owned subsidiary of CenterPoint Energy that provides electric transmission service to transmission service customers in the ERCOT region and distribution service to REPs serving the Texas Gulf Coast area that includes the city of Houston.

CERC Corp. is an indirect, wholly-owned subsidiary of CenterPoint Energy that owns and operates natural gas distribution facilities in six states, with operating subsidiaries that own and operate permanent pipeline connections through interconnects with various interstate and intrastate pipeline companies, and provide temporary delivery of LNG and CNG throughout the contiguous 48 states.

In this Management’s Discussion and Analysis, we discuss our results from continuing operations on a consolidated basis and individually for each of our 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. 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, among other factors.

During the fourth quarter of 2020, CenterPoint Energy’s CODM requested that the financial information for the electric businesses be presented on an aggregated basis for review, resulting in one Electric reportable segment, comprised of Houston Electric and Indiana Electric. Also, the Natural Gas Distribution reportable segment was renamed Natural Gas. Additionally, during the fourth quarter of 2020, CenterPoint Energy’s CODM requested that the CERC corporate functions be included within the financial results of CenterPoint Energy’s Natural Gas reportable segment for review purposes. During the fourth quarter of 2020, CERC’s CODM requested that the CERC corporate functions be included within the financial results of CERC’s Natural Gas reportable segment for review purposes. As a result of this change, and following the divestiture of the Energy Services Disposal Group, CERC now consists of a single reportable segment. Houston Electric also consists of a single reportable segment.

As of December 31, 2020, CenterPoint Energy’s reportable segments were Electric, Natural Gas and Midstream Investments.

CenterPoint Energy’s Corporate and Other includes office buildings and other real estate used for business operations, energy performance contracting and sustainable infrastructure services and other corporate support operations.

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.

We are an energy delivery company. The majority of our revenues are generated from the transmission and delivery of electricity and the sale of natural gas by our subsidiaries. On February 1, 2019, we acquired Vectren for approximately $6 billion in cash. Through its subsidiaries, Vectren’s operations consist of utility and non-utility businesses. The utility operations include three public utilities, Indiana Gas, SIGECO and VEDO, which, in the aggregate, provide natural gas distribution and transportation services to nearly 67% of Indiana and about 20% of Ohio and electric transmission and distribution services to southwestern Indiana, including power generating and wholesale power operations. In total, these utility operations supply natural gas and electricity to over one million customers in Indiana and Ohio. The non-utility operations included ESG and Infrastructure Services. ESG provides energy services through performance-based energy contracting operations and sustainable infrastructure services, such as renewables, distributed generation and combined heat and power projects. ESG assists schools, hospitals, governmental facilities and other private institutions with reducing energy and maintenance costs by upgrading their facilities with energy-efficient equipment. ESG operates throughout the United States. Infrastructure Services, through its wholly-owned subsidiaries, provided underground pipeline and repair services to many utilities, including our utilities, as well as other industries. Concurrent with the completion of the Merger in 2019, we added two new reportable segments, Indiana Electric Integrated and Infrastructure Services. On February 3, 2020, CenterPoint Energy, through its subsidiary VUSI, entered into the Securities Purchase Agreement to sell the Infrastructure Services Disposal Group. The transaction closed on April 9, 2020. For further information, see Note 4 to the consolidated financial statements. During the fourth quarter of 2020, CenterPoint Energy’s CODM requested that the financial information for the electric businesses be presented on an aggregated basis for review, resulting in one Electric reportable segment, comprised of Houston Electric and Indiana Electric. See Note 18 for further changes on reportable segments during 2020.

To assess our financial performance, our management primarily monitors net income and cash flows, among other things, from our reportable segments. Within these broader financial measures, we monitor margins, 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 our reportable segments, including the number of customers, throughput, use per customer,

The nature of our businesses requires significant amounts of capital investment, and we rely on internally generated cash, borrowings under our credit facilities, proceeds from commercial paper and issuances of debt and equity in the capital markets to satisfy these capital needs. With respect to CERC, we intend to use proceeds from any potential asset sales, including the potential dispositions of our Natural Gas businesses in Arkansas and Oklahoma, to satisfy a portion of its 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 can also affect the availability of new capital on terms we consider attractive. In those circumstances, 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.

To the extent adverse economic conditions affect our suppliers and customers, results from our energy delivery businesses may suffer. For example, the economic impacts of COVID-19 have been felt nationwide, with every region of the country experiencing deep reductions in employment in the second quarter of 2020. We believe that all of the states that we serve have improved economically since then and continue to recover, although at different rates. 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, Texas, 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 eight states our utility businesses serve. In Minnesota, for instance, education and health services are the state’s largest sectors, whereas Arkansas has a large food manufacturing industry. 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.

Also, adverse economic conditions, coupled with concerns for protecting the environment and increased availability of alternate energy sources, may cause consumers to use less energy or avoid expansions of their facilities, including natural gas facilities, resulting in less demand for our services. Long-term national trends indicate customers have reduced their energy consumption, which could adversely affect our results. However, due to more affordable energy prices and continued economic improvement in the areas we serve, the trend toward lower usage has slowed. To the extent population growth is affected by lower energy prices and there is financial pressure on some of our customers who operate within the energy industry, there may be an impact on the growth rate of our customer base and overall demand. Despite the overall economic impact of the recession, housing growth has continued and accelerated in 2020. Lower interest rates have helped single family housing starts in the Houston and Minneapolis to exceed growth in previous years. Multifamily residential customer growth is affected by the cyclical nature of apartment construction. Beginning in 2019 and continuing through 2020, a new construction cycle in Houston helped overall residential customer growth to surpass the long-term trend of 2%. Management expects residential meter growth for Houston Electric to remain in line with long term trends at approximately 2%. Typical customer growth in the jurisdictions served by the Natural Gas reportable segment is approximately 1%. CERC’s Natural Gas customer growth was 1.7% for 2020, which is slightly higher than in previous years. Management expects residential meter growth for CERC to remain in line with long term trends at approximately 1%.

Performance of the Electric reportable segment and the Natural Gas reportable segment is significantly influenced by energy usage per customer, which is significantly impacted by weather conditions. For Houston Electric, revenues are generally higher during the warmer months when more electricity is used for cooling purposes. For Indiana Electric, a significant portion of its 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. For CERC’s Natural Gas, demand for natural gas for heating purposes is generally higher in the colder months. Therefore, we compare our results on a weather-adjusted basis. 

In 2020, the Houston area experienced weather that was warmer than normal compared to 2019. Although the summer months were somewhat hotter than normal, the warmer than normal temperatures started early in the year with a mild winter. Our Natural Gas service territories experienced warmer weather in 2020 than it has since 2017. Historically, both CenterPoint Energy’s TDU and CERC’s Natural Gas have utilized weather hedges to help reduce the impact of mild weather on their financial results. CenterPoint Energy’s TDU and CERC’s Natural Gas entered into a weather hedge for the 2019–2020 winter heating season in Texas where no weather normalization mechanisms exist. In CERC’s non-Texas jurisdictions, weather

In our Natural Gas Indiana and Ohio service territories, normal temperature adjustment and decoupling mechanisms largely mitigate the effect that would otherwise be caused by variations in volumes sold to these customers due to weather and changing consumption patterns. Our Natural Gas operations in Ohio has a straight fixed variable rate design for its residential customers. This rate design mitigates approximately 90% of the Ohio service territory’s weather risk and risk of decreasing consumption specific to its small customer classes. While Indiana Electric has neither a normal temperature adjustment mechanism nor a decoupling mechanism, rate designs provide for a lost margin recovery mechanism that operates in tandem with conservation initiatives.

Sales of natural gas to residential and commercial customers by Indiana Gas, SIGECO and VEDO are largely seasonal and are impacted by weather. Trends in the average consumption among natural gas residential and commercial customers have tended to decline as more efficient appliances and furnaces are installed, and as these utilities have implemented conservation programs. 

For CERC’s Natural Gas in Minnesota and Arkansas, rate adjustment mechanisms counter the impact of changes in customer usage. In addition, in many of our service areas, particularly in the Houston area and Minnesota, as applicable to each registrant, we have benefited from growth in the number of customers. 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 our electric and natural gas distribution rates.

For details related to our pending and completed regulatory proceedings and orders in 2020 and to date in 2021, see “—Liquidity and Capital Resources —Regulatory Matters” in Item 7 of Part II of this report, which discussion is incorporated herein by reference.

We believe the long-term outlook for ESG’s performance contracting and sustainable infrastructure opportunities remains strong with continued national focus expected on energy conservation and sustainability, renewable energy and security as power prices across the country rise and customer focus on new, efficient and clean sources of energy grows.

The regulation of natural gas pipelines and related facilities by federal and state regulatory agencies affects CenterPoint Energy’s and CERC’s businesses. In accordance with natural gas pipeline safety and integrity regulations, CenterPoint Energy and CERC are making, and will continue to make, significant capital investments in their service territories, which are necessary to help operate and maintain a safe, reliable and growing natural gas system. CenterPoint Energy’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 they serve are necessary to recover these increasing costs.

Consistent with the regulatory treatment of pension costs, the Registrants defer the amount of pension expense that differs from the level of pension expense included in the Registrants’ base rates for the Electric reportable segment and Natural Gas reportable segment in their Texas jurisdictions. CenterPoint Energy expects to contribute a minimum of approximately $61 million to its pension plans in 2021.

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

Enable expects its business to continue to be impacted by the trends affecting the midstream industry. Enable’s outlook is based on its management’s assumptions regarding the impact of these trends that it has developed by interpreting the information currently available to it. If Enable management’s assumptions or interpretation of available information prove to be incorrect, Enable’s future financial condition and results of operations may differ materially from its expectations.

Enable’s business is impacted by commodity prices, which have remained historically low and otherwise experienced significant volatility in recent years, including due to the effects of the COVID-19 pandemic, among other factors. Commodity prices impact the drilling and production of natural gas and crude oil in the areas served by Enable’s systems, and the volumes

Enable’s long-term view is that natural gas and crude oil will continue to be a critical component of energy demand in the United States and worldwide because natural gas has lower emissions and is a practical fuel for a variety of applications. As electric energy demand continues to grow, Enable’s management believes that natural gas will continue to replace coal. As the global market for LNG continues to develop, Enable’s management believes that natural gas supply in the United States is well positioned to address demand in the United States, as well as in other areas of the world, including Western Europe and Asia. As the desire to lower emissions continues, Enable’s management believes that natural gas will be seen as a practical alternative to higher-emissions liquids fuels, such as bunker fuels in international shipping. Supplies of crude oil have risen primarily from the success of unconventional drilling in tight oil plays across the United States. Liquid fuels derived from crude oil have remained a primary source of energy in the United States, and exports of crude oil and liquid fuels from the United States have risen dramatically over the last five years. As the supply of crude oil has increased in the United States, Enable’s management believes that the United States will continue to be a source of supply to the global crude oil market.

For information on the Enable Merger, see Note 22 to the consolidated financial statements.

We have experienced some resulting disruptions to our business operations, as these restrictions significantly impacted, and may continue to impact, many sectors of the economy with various businesses curtailing or ceasing normal operations. For example, since mid-March 2020, we have had to restrict access to certain office locations around the United States. However, as of the date of this Form 10-K, we have increased the permitted occupancy of certain of our offices and facilities. The rest of our office-based personnel continue to be productive through alternate work arrangements, leveraging a strong technology platform to support our employees working remotely to perform their duties or directly from their vehicles to serve our customers. Where we must maintain a presence in the field, we have adjusted our operational protocols to minimize exposure and risk to our field personnel, customers and the communities we serve, including, among other things, modifying our work schedules and reporting locations, potentially delaying certain work types as appropriate, such as maintenance and capital projects, and adjusting project scope and scale to adhere to safety protocols, while continuing to maintain the work activities necessary for safe and reliable service to our customers with increased safety precautions. While certain of our personnel have been, and may continue to be, quarantined, our operations and corporate functions have not been adversely affected to date.

Certain of our Natural Gas service territories were impacted by Hurricane Laura in August 2020, as well as Hurricanes Sally, Delta and Zeta in October 2020. While our Natural Gas field personnel assessed and stabilized our impacted Natural Gas facilities, our electric operations mutual assistance crews from Texas and Indiana worked safely to support the storm restoration efforts of other impacted utilities. Despite COVID-19 conditions, neither our personnel nor our facilities experienced significant performance or operational impacts from Hurricanes Laura, Sally, Delta and Zeta.

Our first priority in our response to this pandemic has been the health and safety of our employees, our customers and other business counterparties. Because we provide a critical service to our customers, it is paramount that we keep our employees who operate our business safe and informed, and we have taken and are updating precautions for that purpose. We have implemented preventative measures and developed corporate and regional response plans to minimize unnecessary risk of exposure and prevent infection, while supporting our customers’ operations under the circumstances. When an employee tests positive for COVID-19, we investigate appropriately and take action to identify and notify potentially exposed individuals, coordinate testing and clean work locations, among other precautionary measures. If our employees feel sick or are awaiting COVID-19 test results, they do not report to their respective work locations to protect the health and safety of other employees. In addition, we have assessed and updated our existing business continuity plans for each of our business units in the context of this pandemic. We have a corporate response planning team who assesses risks to our business, including for health, safety and environmental matters and personnel issues, and addresses various impacts of the situation, as they have developed. Throughout the year, this corporate response planning team has provided periodic updates on COVID-19 to the Board of Directors, which has responsibility for, and is actively involved in, the oversight of risks that could impact CenterPoint Energy. We also have modified certain business practices (including those related to employee travel, employee work locations and participation in meetings, events and conferences) to conform to government restrictions and best practices encouraged by the Centers for Disease Control and Prevention, the World Health Organization and other governmental and regulatory authorities. We are continuing to address concerns to protect the health and safety of our employees and those of our customers and other business counterparties, and this includes changes to comply with health-related guidelines as they are modified and supplemented. We are continuing to work with our suppliers on any potential impacts to our supply chain, including identifying any negative impacts to material supplies, working to mitigate them and pre-planning for longer-term emergency response protocols. Since March 2020, we have not experienced significant disruptions or challenges with respect to our supply chain from the COVID-19 pandemic as a result of the aforementioned efforts with our core vendors and suppliers. This is a continuously evolving situation and could lead to further disruption of economic activity in our markets; we will continue to monitor developments affecting our workforce, our customers and our suppliers and take additional precautions as we believe are warranted.

The extended slowdown of economic growth, decreased demand for commodities and material changes in governmental or regulatory policy in the United States has resulted in, and could continue to result in, lower growth, including, in certain instances, customer growth, and reduced demand for and usage of electricity and natural gas in our service territories as customer facilities continue to close or remain closed. While residential electric usage has increased as individuals continue to stay at home or work remotely, our business has experienced reduced demand and usage among our electric and natural gas commercial and industrial customers as well as a decrease in revenues from disconnections and reconnections due to the disconnect moratoriums across our service territories due to COVID-19, which have either expired or may expire during the

Due to macroeconomic conditions related in part to the COVID-19 pandemic and the decline in our Common Stock price, we identified a triggering event to perform an interim goodwill impairment test as of March 31, 2020 and recognized a non-cash goodwill impairment charge of $185 million in our Indiana Electric Integrated reporting unit for the three months ended March 31, 2020. For further discussion of this impairment, see Note 10 to the consolidated financial statements. CenterPoint Energy and CERC performed their annual goodwill impairment tests in the third quarter of 2020 and determined that no goodwill impairment charge was required for any reporting unit as a result of those tests. No triggering events occurred and no impairment tests were performed for subsequent periods.

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 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, 2020, 2019 and 2018 was as follows: