10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

______________________

Form 10-K

(Mark One)
☑	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	FOR THE FISCAL YEAR ENDED DECEMBER 31, 2019
OR
☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	FOR THE TRANSITION PERIOD FROM                TO

	Registrant, State or Other Jurisdiction  of Incorporation or Organization
Commission file number	Address of Principal Executive Offices, Zip Code  and Telephone Number			I.R.S. Employer Identification No.
1-31447	CenterPoint Energy, Inc.			74-0694415
	(a Texas corporation)
	1111 Louisiana
	Houston,	Texas	77002
	(713)	207-1111
1-3187	CenterPoint Energy Houston Electric, LLC			22-3865106
	(a Texas limited liability company)
	1111 Louisiana
	Houston,	Texas	77002
	(713)	207-1111
1-13265	CenterPoint Energy Resources Corp.			76-0511406
	(a Delaware corporation)
	1111 Louisiana
	Houston,	Texas	77002
	(713)	207-1111

Securities registered pursuant to Section 12(b) of the Act:
Registrant	Title of each class	Trading symbol(s)	Name of each exchange on which registered
CenterPoint Energy, Inc.	Common Stock, $0.01 par value	CNP	New York Stock Exchange
			Chicago Stock Exchange
CenterPoint Energy, Inc.	Depositary shares, each representing a 1/20th interest in a share of 7.00% Series B Mandatory Convertible Preferred Stock, $0.01 par value	CNP/PB	New York Stock Exchange
CenterPoint Energy Houston Electric, LLC	9.15% First Mortgage Bonds due 2021	n/a	New York Stock Exchange
CenterPoint Energy Houston Electric, LLC	6.95% General Mortgage Bonds due 2033	n/a	New York Stock Exchange
CenterPoint Energy Resources Corp.	6.625% Senior Notes due 2037	n/a	New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

CenterPoint Energy, Inc.	Yes	þ	No o
CenterPoint Energy Houston Electric, LLC	Yes	þ	No o
CenterPoint Energy Resources Corp.	Yes	þ	No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  

CenterPoint Energy, Inc.	Yes o	No	þ
CenterPoint Energy Houston Electric, LLC	Yes o	No	þ
CenterPoint Energy Resources Corp.	Yes o	No	þ

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  

CenterPoint Energy, Inc.	Yes	þ	No o
CenterPoint Energy Houston Electric, LLC	Yes	þ	No o
CenterPoint Energy Resources Corp.	Yes	þ	No o

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). 

CenterPoint Energy, Inc.	Yes	þ	No o
CenterPoint Energy Houston Electric, LLC	Yes	þ	No o
CenterPoint Energy Resources Corp.	Yes	þ	No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer”, “accelerated filer”, “smaller reporting company”, and “emerging growth company” in Rule 12b-2 of the Exchange Act.

	Large accelerated filer	Accelerated filer	Non-accelerated filer	Smaller reporting company	Emerging growth company
CenterPoint Energy, Inc.	þ	o	o	☐	☐
CenterPoint Energy Houston Electric, LLC	o	o	þ	☐	☐
CenterPoint Energy Resources Corp.	o	o	þ	☐	☐

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

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

The aggregate market values of the voting stock held by non-affiliates of the Registrants as of June 28, 2019 are as follows:

CenterPoint Energy, Inc. (using the definition of beneficial ownership contained in Rule 13d-3 promulgated pursuant to Securities Exchange Act of 1934 and excluding shares held by directors and executive officers)	$14,295,717,409
CenterPoint Energy Houston Electric, LLC	None
CenterPoint Energy Resources Corp.	None

Indicate the number of shares outstanding of each of the issuers’ classes of common stock as of  February 19, 2020:

CenterPoint Energy, Inc.	502,243,185	shares of common stock outstanding, excluding 166 shares held as treasury stock
CenterPoint Energy Houston Electric, LLC	1,000	common shares outstanding, all held by Utility Holding, LLC, a wholly-owned subsidiary of CenterPoint Energy, Inc.
CenterPoint Energy Resources Corp.	1,000	shares of common stock outstanding, all held by Utility Holding, LLC, a wholly-owned subsidiary of CenterPoint Energy, Inc.

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

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the definitive proxy statement relating to the 2020 Annual Meeting of Shareholders of CenterPoint Energy, which will be filed with the Securities and Exchange Commission within 120 days of December 31, 2019, are incorporated by reference in Item 10, Item 11, Item 12, Item 13 and Item 14 of Part III of this Form 10-K.

TABLE OF CONTENTS

PART I
		Page
Item 1.	Business	1
Item 1A.	Risk Factors	23
Item 1B.	Unresolved Staff Comments	51
Item 2.	Properties	51
Item 3.	Legal Proceedings	52
Item 4.	Mine Safety Disclosures	52
PART II
Item 5.	Market for Registrants’ Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	52
Item 6.	Selected Financial Data	52
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	53
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	99
Item 8.	Financial Statements and Supplementary Data	102
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	204
Item 9A.	Controls and Procedures	204
Item 9B.	Other Information	207
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	207
Item 11.	Executive Compensation	208
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	208
Item 13.	Certain Relationships and Related Transactions, and Director Independence	208
Item 14.	Principal Accounting Fees and Services	208
PART IV
Item 15.	Exhibits and Financial Statement Schedules	209
Item 16.	Form 10-K Summary	210

i

GLOSSARY
ACE	Affordable Clean Energy
ADFIT	Accumulated deferred federal income taxes
ADMS	Advanced Distribution Management System
AEM	Atmos Energy Marketing, LLC, previously a wholly-owned subsidiary of Atmos Energy Holdings, Inc., a wholly-owned subsidiary of Atmos Energy Corporation
AFUDC	Allowance for funds used during construction
AGC	Alcoa Generating Corporation, a subsidiary of Alcoa, Inc.
Athena Energy Services	Athena Energy Services Buyer, LLC, a Delaware limited liability company and subsidiary of Energy Capital Partners, LLC
AMAs	Asset Management Agreements
AMS	Advanced Metering System
APSC	Arkansas Public Service Commission
ARAM	Average rate assumption method
ARO	Asset retirement obligation
ARP	Alternative revenue program
ASC	Accounting Standards Codification
ASU	Accounting Standards Update
AT&T	AT&T Inc.
AT&T Common	AT&T common stock
Bailey to Jones Creek Project	A transmission project in the greater Freeport, Texas area, which includes enhancements to two existing substations and the construction of a new 345 kV double-circuit line to be located in the counties of Brazoria, Matagorda and Wharton
Bcf	Billion cubic feet
Bond Companies	Bankruptcy remote entities wholly-owned by Houston Electric and formed solely for the purpose of purchasing and owning transition or system restoration property through the issuance of Securitization Bonds, consisting of Bond Company II, Bond Company III, Bond Company IV and Restoration Bond Company
Bond Company II	CenterPoint Energy Transition Bond Company II, LLC, a wholly-owned subsidiary of Houston Electric
Bond Company III	CenterPoint Energy Transition Bond Company III, LLC, a wholly-owned subsidiary of Houston Electric
Bond Company IV	CenterPoint Energy Transition Bond Company IV, LLC, a wholly-owned subsidiary of Houston Electric
Brazos Valley Connection	A portion of the Houston region transmission project between Houston Electric’s Zenith substation and the Gibbons Creek substation owned by the Texas Municipal Power Agency
Bridge Facility	A $5 billion 364-day senior unsecured bridge term loan facility
BTA	Best technology available
CCR	Coal Combustion Residuals
CEA	Commodities Exchange Act of 1936
CECA	Clean Energy Cost Adjustment
CECL	Current expected credit losses
CEIP	CenterPoint Energy Intrastate Pipelines, LLC
CenterPoint Energy	CenterPoint Energy, Inc., and its subsidiaries
CERC Corp.	CenterPoint Energy Resources Corp.
CERC	CERC Corp., together with its subsidiaries
CERCLA	Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended
CES	CenterPoint Energy Services, Inc., a wholly-owned subsidiary of CERC Corp.
CFTC	Commodity Futures Trading Commission
Charter Common	Charter Communications, Inc. common stock
CIP	Conservation Improvement Program
CME	Chicago Mercantile Exchange
CNG	Compressed natural gas

ii

GLOSSARY
CNP Midstream	CenterPoint Energy Midstream, Inc., a wholly-owned subsidiary of CenterPoint Energy
Code	The Internal Revenue Code of 1986, as amended
Common Stock	CenterPoint Energy, Inc. common stock, par value $0.01 per share
Continuum	The retail energy services business of Continuum Retail Energy Services, LLC, including its wholly-owned subsidiary Lakeshore Energy Services, LLC and the natural gas wholesale assets of Continuum Energy Services, LLC
CPP	Clean Power Plan
CSIA	Compliance and System Improvement Adjustment
DCA	Distribution Contractors Association
DCRF	Distribution Cost Recovery Factor
Dodd-Frank Act	Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010
DOT	U.S. Department of Transportation
DRR	Distribution Replacement Rider
DSMA	Demand Side Management Adjustment
Dth	Dekatherms
ECA	Environmental Cost Adjustment
EDIT	Excess deferred income taxes
EECR	Energy Efficiency Cost Recovery
EECRF	Energy Efficiency Cost Recovery Factor
EGT	Enable Gas Transmission, LLC
EIN	Employer Identification Number
ELG	Effluent Limitation Guidelines
Enable	Enable Midstream Partners, LP
Enable GP	Enable GP, LLC, Enable’s general partner
Enable Series A Preferred Units	Enable’s 10% Series A Fixed-to-Floating Non-Cumulative Redeemable Perpetual Preferred Units, representing limited partner interests in Enable
EPA	Environmental Protection Agency
EPAct of 2005	Energy Policy Act of 2005
Equity Purchase Agreement	Equity Purchase Agreement, dated as of February 24, 2020, by and between CERC Corp. and Athena Energy Services
ERCOT	Electric Reliability Council of Texas
ERCOT ISO	ERCOT Independent System Operator
ERISA	Employee Retirement Income Security Act of 1974
ERO	Electric Reliability Organization
ESG	Energy Systems Group, LLC, a wholly-owned subsidiary of Vectren
ESPC	Energy Savings Performance Contracting
FAC	Fuel Adjustment Clause
FERC	Federal Energy Regulatory Commission
FIP	Funding Improvement Plan
Fitch	Fitch Ratings, Inc.
FPA	Federal Power Act
FRP	Formula Rate Plan
Gas Daily	Platts gas daily indices
GenOn	GenOn Energy, Inc.
GHG	Greenhouse gases
GRIP	Gas Reliability Infrastructure Program
GWh	Gigawatt-hours
Hart-Scott-Rodino Act	Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended
Houston Electric	CenterPoint Energy Houston Electric, LLC and its subsidiaries
HVAC	Heating, ventilation and air conditioning

iii

GLOSSARY
IBEW	International Brotherhood of Electrical Workers
ICA	Interstate Commerce Act of 1887
ICPA	Inter-Company Power Agreement
IDEM	Indiana Department of Environmental Management
IG	Intelligent Grid
Indiana Electric	Operations of SIGECO’s electric transmission and distribution services, and includes its power generating and wholesale power operations
Indiana Gas	Indiana Gas Company, Inc., a wholly-owned subsidiary of Vectren
Infrastructure Services	Provides underground pipeline construction and repair services through Vectren’s wholly-owned subsidiaries Miller Pipeline, LLC and Minnesota Limited, LLC
Internal Spin	CERC’s contribution of its equity investment in Enable to CNP Midstream (detailed in Note 11 to the consolidated financial statements)
IRP	Integrated Resource Plan
IRS	Internal Revenue Service
IURC	Indiana Utility Regulatory Commission
kV	Kilovolt
LIBOR	London Interbank Offered Rate
LNG	Liquefied natural gas
LPSC	Louisiana Public Service Commission
LTIPs	Long-term incentive plans
MATS	Mercury and Air Toxics
MCRA	MISO Cost and Revenue Adjustment
Meredith	Meredith Corporation
Merger	The merger of Merger Sub with and into Vectren on the terms and subject to the conditions set forth in the Merger Agreement, with Vectren continuing as the surviving corporation and as a wholly-owned subsidiary of CenterPoint Energy, Inc., which closed on February 1, 2019
Merger Agreement	Agreement and Plan of Merger, dated as of April 21, 2018, among CenterPoint Energy, Vectren and Merger Sub
Merger Sub	Pacer Merger Sub, Inc., an Indiana corporation and wholly-owned subsidiary of CenterPoint Energy
MES	Mobile Energy Solutions
MGP	Manufactured gas plant
MISO	Midcontinent Independent System Operator
MLP	Master Limited Partnership
MMBtu	One million British thermal units
MMcf	Million cubic feet
Moody’s	Moody’s Investors Service, Inc.
MP2017	2017 pension mortality improvement scale developed annually by the Society of Actuaries
MP2018	2018 pension mortality improvement scale developed annually by the Society of Actuaries
MPSC	Mississippi Public Service Commission
MPUC	Minnesota Public Utilities Commission
MRT	Enable-Mississippi River Transmission, LLC
Mva	Megavolt amperes
MW	Megawatt
NECA	National Electrical Contractors Association
NERC	North American Electric Reliability Corporation
NESHAPS	National Emission Standards for Hazardous Air Pollutants
NGA	Natural Gas Act of 1938
NGD	Natural gas distribution business
NGLs	Natural gas liquids
NGPA	Natural Gas Policy Act of 1978

iv

GLOSSARY
NGPSA	Natural Gas Pipeline Safety Act of 1968
NOPR	Notice of Proposed Rulemaking
NRG	NRG Energy, Inc.
NYMEX	New York Mercantile Exchange
NYSE	New York Stock Exchange
OCC	Oklahoma Corporation Commission
OGE	OGE Energy Corp.
OPEIU	Office & Professional Employees International Union
OVEC	Ohio Valley Electric Corporation
PAS	Power Alert Service
PBRC	Performance Based Rate Change
PFD	Proposal for decision
PHMSA	Pipeline and Hazardous Materials Safety Administration
PLCA	Pipeline Contractors Association
PowerTeam Services	PowerTeam Services, LLC, a Delaware limited liability company
PRPs	Potentially responsible parties
PUCO	Public Utilities Commission of Ohio
PUCT	Public Utility Commission of Texas
Railroad Commission	Railroad Commission of Texas
RCRA	Resource Conservation and Recovery Act of 1976
RCRA Mechanism	Reliability Cost and Revenue Adjustment mechanism
Registrants	CenterPoint Energy, Houston Electric and CERC, collectively
Reliant Energy	Reliant Energy, Incorporated
REP	Retail electric provider
Restoration Bond Company	CenterPoint Energy Restoration Bond Company, LLC, a wholly-owned subsidiary of Houston Electric
Revised Policy Statement	Revised Policy Statement on Treatment of Income Taxes
RICE MACT	Reciprocating Internal Combustion Engines Maximum Achievable Control Technology
ROE	Return on equity
RP	Rehabilitation Plan
RRA	Rate Regulation Adjustment
RRI	Reliant Resources, Inc.
RSP	Rate Stabilization Plan
SEC	Securities and Exchange Commission
SESH	Southeast Supply Header, LLC
Securities Purchase Agreement	Securities Purchase Agreement, dated as of February 3, 2020, by and among VUSI, PowerTeam Services and, solely for purposes of Section 10.17 of the Securities Purchase Agreement, Vectren
Securitization Bonds	Transition and system restoration bonds
Series A Preferred Stock	CenterPoint Energy’s Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Stock, par value $0.01 per share, with a liquidation preference of $1,000 per share
Series B Preferred Stock	CenterPoint Energy’s 7.00% Series B Mandatory Convertible Preferred Stock, par value $0.01 per share, with a liquidation preference of $1,000 per share
SIGECO	Southern Indiana Gas and Electric Company, a wholly-owned subsidiary of Vectren
S&P	S&P Global Ratings
TBD	To be determined
TCEH Corp.	Formerly Texas Competitive Electric Holdings Company LLC, predecessor to Vistra Energy Corp. whose major subsidiaries include Luminant and TXU Energy
TCJA	Tax reform legislation informally called the Tax Cuts and Jobs Act of 2017
TCOS	Transmission Cost of Service

v

GLOSSARY
TCRF	Transmission Cost Recovery Factor
TDSIC	Transmission, Distribution and Storage System Improvement Charge
TDU	Transmission and distribution utility
Time	Time Inc.
Transition Agreements	Services Agreement, Employee Transition Agreement, Transitional Seconding Agreement and other agreements entered into in connection with the formation of Enable
Texas RE	Texas Reliability Entity
TW	Time Warner Inc.
TW Common	TW common stock
UESC	Utility Energy Services Contract
USW	United Steelworkers Union
Utility Holding	Utility Holding, LLC, a wholly-owned subsidiary of CenterPoint Energy
VaR	Value at Risk
Vectren	Vectren Corporation, a wholly-owned subsidiary of CenterPoint Energy
VEDO	Vectren Energy Delivery of Ohio, Inc., a wholly-owned subsidiary of Vectren
VIE	Variable interest entity
VISCO	Vectren Infrastructure Services Corporation, a wholly-owned subsidiary of Vectren
Vistra Energy Corp.	Texas-based energy company focused on the competitive energy and power generation markets
VUHI	Vectren Utility Holdings, Inc., a wholly-owned subsidiary of Vectren
VUSI	Vectren Utility Services, Inc., a wholly-owned subsidiary of Vectren
WACC	Weighted average cost of capital
ZENS	2.0% Zero-Premium Exchangeable Subordinated Notes due 2029
ZENS-Related Securities	As of both December 31, 2019 and 2018, consisted of AT&T Common and Charter Common
2002 Act	Pipeline Safety Improvement Act of 2002
2006 Act	Pipeline Inspection, Protection, Enforcement and Safety Act of 2006
2011 Act	Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011
2016 Act	Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016

vi

 CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

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 and CERC.

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.

vii

PART I

Item 1. Business

This combined Form 10-K is filed separately by three registrants: CenterPoint Energy, Inc., CenterPoint Energy Houston Electric, LLC and CenterPoint Energy Resources Corp. Information contained herein relating to any individual registrant is filed by such registrant solely on its own behalf. Each registrant makes no representation as to information relating exclusively to the other registrants. 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.

OUR BUSINESS

Overview

CenterPoint Energy is a public utility holding company and owns interests in Enable. CenterPoint Energy’s operating subsidiaries own and operate electric transmission and distribution, electric generation and natural gas distribution facilities, supply natural gas to commercial and industrial customers and electric and natural gas utilities and provide underground pipeline construction and repair services, energy performance contracting and sustainable infrastructure services.

Houston Electric is an indirect, wholly-owned subsidiary of CenterPoint Energy that provides electric transmission and distribution services 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 with operating subsidiaries that own and operate natural gas distribution facilities in six states and supply natural gas to commercial and industrial customers and electric and natural gas utilities in over 30 states.

CenterPoint Energy’s simplified corporate structure as of December 31, 2019 is shown below:

    

(1) Houston Electric engages in the electric transmission and distribution business in the Texas Gulf Coast area that includes the city of Houston.

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

1

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

(4) CES obtains and offers competitive variable and fixed-price physical natural gas supplies and services primarily to commercial and industrial customers and electric and natural gas utilities in over 30 states.

(5) As of December 31, 2019, CNP Midstream owned approximately 53.7% of the common units representing limited partner interests in Enable, which owns, operates and develops natural gas and crude oil infrastructure assets; CNP Midstream also owned 50% of the management rights and 40% of the incentive distribution rights in Enable GP. For additional information regarding CenterPoint Energy’s interest in Enable, including the 14,520,000 Enable Series A Preferred Units directly owned by CenterPoint Energy, see Note 11 to the consolidated financial statements.

(6) Vectren engages in regulated operations through three public utilities:

• Indiana Gas provides energy delivery services to natural gas customers located in central and southern Indiana;

• SIGECO provides energy delivery services to electric and natural gas customers and owns and operates electric generation assets to serve its electric customers and optimizes those assets in the wholesale power market; and

• VEDO provides energy delivery services to natural gas customers in west-central Ohio.

Vectren performs non-utility activities through Infrastructure Services, which provides underground pipeline construction and repair services, and 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 is expected to close in the second quarter of 2020. For further information, see Notes 6 and 23 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. The transaction is expected to close in the second quarter of 2020. For further information, see Notes 6 and 23 to the consolidated financial statements.

CenterPoint Energy’s service territories as of December 31, 2019 are depicted below:

2

As of December 31, 2019, reportable segments by Registrant are as follows:

Registrants	Houston Electric T&D	Indiana Electric Integrated	Natural Gas Distribution	Energy Services	Infrastructure Services	Midstream Investments	Corporate and Other
CenterPoint Energy	X	X	X	X	X	X	X
Houston Electric	X
CERC			X	X			X

For a discussion of operating 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 19 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:

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

• our Ethics and Compliance Code;

• our Corporate Governance Guidelines; and

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

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

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

Houston Electric T&D (CenterPoint Energy and Houston Electric)

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

Electric Transmission

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

3

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

Electric Distribution

In ERCOT, end users purchase 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 existing services are established pursuant to rate proceedings conducted before municipalities that have original jurisdiction and the PUCT.

Bond Companies

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, 2019 and 2018, see Note 14 to the consolidated financial statements.

Customers

Houston Electric serves nearly all of the Houston/Galveston metropolitan area. As of December 31, 2019, Houston Electric’s customers consisted of approximately 68 REPs, which sell electricity to approximately 2.5 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 19 to the consolidated financial statements. The table below reflects the number of metered customers in Houston Electric’s service area as of December 31, 2019:

	Residential	Commercial/ Industrial	Total Customers
Texas Gulf Coast	2,243,188	291,098	2,534,286

Utility Technology

Houston Electric’s Smart Grid is comprised of the AMS, IG, ADMS and private telecommunications network. Houston Electric has deployed fully operational advanced meters to virtually all of its approximately 2.5 million metered customers, automated 95 substations, installed 1,603 IG Switching Devices and other automation devices on more than 450 circuits, built a wireless radio frequency mesh telecommunications network across Houston Electric’s 5,000-square mile footprint, and enabled real-time grid monitoring and control, which leverages information from smart meters and field sensors to manage system events through the ADMS. The Smart Grid continues to improve electric distribution service reliability and restoration, enhance the consumer experience, support the growth of renewable energy and help the environment by reducing carbon emissions.

In addition, Houston Electric has implemented leading capabilities with customer service applications and mobile data applications including the PAS. The PAS notification tool alerts over 1.2 million registered customers of power delivery events at or near their home or facility via text, email or phone call.

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Competition

There are no other electric transmission and distribution utilities in Houston Electric’s service area. For another provider of transmission and distribution services to provide such services in Houston Electric’s territory, it would be required to obtain a certificate of convenience and necessity from the PUCT and, depending on the location of the facilities, may also be required to obtain franchises from one or more municipalities. 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.

Seasonality

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.

Properties

All of Houston Electric’s properties are located in Texas. Its properties consist primarily of high-voltage electric transmission lines and poles, distribution lines, substations, service centers, service wires, telecommunications network and meters. Most of Houston Electric’s transmission and distribution lines have been constructed over lands of others pursuant to easements or along public highways and streets under franchise agreements and as permitted by law.

All real and tangible properties of Houston Electric, subject to certain exclusions, are currently subject to:

• the lien of a Mortgage and Deed of Trust (the Mortgage) dated November 1, 1944, as supplemented; and

• the lien of a General Mortgage (the General Mortgage) dated October 10, 2002, as supplemented, which is junior to the lien of the Mortgage.

For information related to debt outstanding under the Mortgage and General Mortgage, see Note 14 to the consolidated financial statements.

Electric Lines - Transmission and Distribution. As of December 31, 2019, Houston Electric owned and operated the following electric transmission and distribution lines:

	Circuit Miles
Description	Overhead Lines	Underground Lines
Transmission lines - 69 kV	259	2
Transmission lines - 138 kV	2,215	24
Transmission lines - 345 kV	1,337	—
Total transmission lines	3,811	26
Distribution lines	29,303	25,935

Substations.  As of December 31, 2019, Houston Electric owned 236 major substation sites having a total installed rated transformer capacity of 68,053 Mva.

Service Centers.  As of December 31, 2019, Houston Electric operated 15 regional service centers located on a total of 345 acres of land. These service centers consist of office buildings, warehouses and repair facilities that are used in the business of transmitting and distributing electricity.

Franchises

Houston Electric holds non-exclusive franchises from certain incorporated municipalities in its service territory. In exchange for the payment of fees, these franchises give Houston Electric the right to use the streets and public rights-of-way of these municipalities to construct, operate and maintain its transmission and distribution system and to use that system to conduct its

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electric delivery business and for other purposes that the franchises permit. The terms of the franchises, with various expiration dates, typically range from 20 to 40 years.

Indiana Electric Integrated (CenterPoint Energy)

Upon consummation of the Merger, CenterPoint Energy added Indiana Electric Integrated as a new reportable segment. Indiana Electric Integrated consists of SIGECO’s electric transmission and distribution services, including its power generating and wholesale power operations. As of December 31, 2019, Indiana Electric supplied electric service to the following:

	Residential	Commercial/Industrial	Total Customers
Indiana	128,947	18,995	147,942

System Load

Total load and the related reserve margin at the time of the system summer peak on September 12, 2019, is presented below in MW, except for reserved margin at peak.

	2019
Total load at peak	1,055
Generating capability	1,167
Purchase supply (effective capacity)	60
Interruptible contracts & direct load control	62
Total power supply capacity	1,289
Reserve margin at peak	22	%

The winter peak load for the 2018-2019 season of approximately 757 MW occurred on January 30, 2019. 

Coal Purchases

Coal for coal-fired generating stations has been supplied from operators of nearby coal mines as there are substantial coal reserves in the southern Indiana area. Approximately 2.6 million tons were purchased for generating electricity during 2019. Indiana Electric’s coal inventory was approximately 664,000 tons as of December 31, 2019. The average cost of coal per ton purchased and delivered in 2019 was $50.67. Since August 2014, Indiana Electric has purchased substantially all of its coal from Sunrise Coal, LLC.

Firm Purchase Supply

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, 2019, 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 eligible 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 December 31, 2019, Indiana Electric’s 1.5% share of OVEC’s debt obligation equates to between $20 million and $25 million, depending on revolving capacity commitments. Despite the bankruptcy proceedings of one of OVEC’s shareholders that holds a 4.9% interest under the ICPA, OVEC has represented it has both liquidity and financing capability that will allow it to continue to operate and provide power to its participating members, who include American Electric Power Company Inc., Duke Energy Corporation, and PPL Corporation. In 2019, Indiana Electric purchased approximately 121 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, the Ohio Legislature enacted House Bill 6, which provides for financial support to the members of OVEC serving Ohio customers.

In April 2008, Indiana Electric executed a capacity contract with Benton County Wind Farm, LLC to purchase as much as 30 MW of energy from a wind farm located in Benton County, Indiana, with IURC approval. The contract expires in 2029. Indiana

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Electric purchased approximately 71 GWh in 2019 under this contract. 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 in 2019 under this contract. In total, wind resources provided 4% of total GWh sourced in 2019.

MISO Related Activity

Indiana Electric is a member of the MISO, a FERC approved regional transmission organization. The MISO serves the electric transmission needs of much of the Midcontinent region and maintains operational control over Indiana Electric’s electric transmission facilities as well as other utilities in the region. Indiana Electric is an active participant in the MISO energy markets, where it bids its generation into the Day Ahead and Real Time markets and procures power for its retail customers at LMP 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 2019, in intervals when purchases from the MISO were in excess of generation sold to the MISO, the net purchases were 447 GWh. During the year ended December 31, 2019, in intervals when sales to the MISO were in excess of purchases from the MISO, the net sales were 377 GWh.

Interconnections

As of December 31, 2019, 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.

Properties

Generating Capacity. As of December 31, 2019, Indiana Electric had 1,167 MW of installed generating capacity, as set forth in the following table.

Generation Source	Unit No.	Location	Date in Service	Capacity (MW)
Coal
A.B. Brown	1	Posey County	1979	245
A.B. Brown	2	Posey County	1986	245
F.B. Culley	2	Warrick County	1966	90
F.B. Culley	3	Warrick County	1973	270
Warrick (1)	4	Warrick County	1970	150
Total Coal Capacity				1,000
Gas (2)
Brown (3)	3	Brown County	1991	80
Brown	4	Brown County	2002	80
Landfill Gas		Pike County	2009	3
Total Gas Capacity				163
Solar
Oak Hill		Evansville, Indiana	2018	2
Volkman		Evansville, Indiana	2018	2
Total Solar Capacity				4
Total Generating Capacity				1,167

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

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(2) The Northeast Gas Turbines with 20 MW of combined capacity were retired in April 2019. Broadway Avenue Unit 2 with 65 MW of capacity was retired in December 2019.

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

Electric Lines - Transmission and Distribution. As of December 31, 2019, Indiana Electric owned and operated the following electric transmission and distribution lines:

	Circuit Miles
Description	Indiana	Kentucky (1)
Transmission lines - 69 kV	548	—
Transmission lines - 138 kV	408	9
Transmission lines - 345 kV	48	15
Total transmission lines	1,004	24

	Circuit Miles
Description	Overhead Lines	Underground Lines
Distribution lines	4,559	2,483

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

Substations.  As of December 31, 2019, Indiana Electric’s transmission system also includes 33 substations with an installed capacity of approximately 4,900 Mva. In addition, Indiana Electric’s distribution system includes 81 distribution substations with an installed capacity of approximately 2,200 Mva and 55,727 distribution transformers with an installed capacity of 2,522 Mva.

Natural Gas Distribution (CenterPoint Energy and CERC)

CenterPoint Energy’s and CERC’s NGD 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 NGD also provides unregulated services in Minnesota consisting of residential appliance repair and maintenance services along with HVAC equipment sales.

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 about 20% of Ohio, primarily in the west-central area. The Indiana and Ohio service areas contain diversified manufacturing and agriculture-related enterprises.

Customers

In 2019, approximately 35% and 39% of CenterPoint Energy’s and CERC’s NGD’s total throughput was to residential customers and approximately 65% and 61% was to commercial and industrial and transportation customers, respectively.

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The table below reflects the number of CenterPoint Energy’s and CERC’s NGD customers by state as of December 31, 2019:

	Residential	Commercial/ Industrial/Transportation	Total Customers
Arkansas	376,160	47,729	423,889
Louisiana	230,248	16,560	246,808
Minnesota	807,713	71,092	878,805
Mississippi	118,601	13,055	131,656
Oklahoma	88,287	10,768	99,055
Texas	1,666,334	101,668	1,768,002
Total CERC NGD	3,287,343	260,872	3,548,215
Indiana	664,665	64,382	729,047
Ohio	300,353	24,495	324,848
Total CenterPoint Energy NGD	4,252,361	349,749	4,602,110

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.

Seasonality

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 2019, approximately 67% of CenterPoint Energy’s NGD’s total throughput and 69% of CERC’s NGD total throughput occurred in the first and fourth quarters. These patterns reflect the higher demand for natural gas for heating purposes during the colder months.

Supply and Transportation.  In 2019, CenterPoint Energy’s NGD purchased virtually all of its natural gas supply pursuant to contracts with remaining terms varying from a few months to four years. Certain contracts are firm commitments under five- and ten-year arrangements. Major suppliers are those that account for greater than 10% of CenterPoint Energy’s or CERC’s annual natural gas supply purchases. In 2019, CenterPoint Energy and CERC purchased 53% and 46% of their natural gas supply from four and three major suppliers, respectively. Numerous other suppliers provided the remainder of CenterPoint Energy’s and CERC’s natural gas supply requirements.

CenterPoint Energy’s and CERC’s NGD 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 NGD anticipates that these gas supply and transportation contracts will be renewed or replaced prior to their expiration.

CenterPoint Energy’s and CERC’s NGD 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 NGD’s physical gas suppliers. Their gas supply plans generally call for 50–75% of winter supplies to be stabilized in some fashion.

The regulations of the states in which CenterPoint Energy’s and CERC’s NGD 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 NGD 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 Energy’s and CERC’s NGD may also supplement contracted supplies and storage from time to time with stored LNG and propane-air plant production.

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As of December 31, 2019, CenterPoint Energy and CERC’s NGD owned and operated the following natural gas facilities:

	No. of Assets	Storage Capacity (Bcf)	Working Capacity (Bcf)	Maximum Daily Withdrawal Rate (MMcf)
CenterPoint Energy
Underground Natural Gas Storage Facility	9	43.6	14.2	337
CERC
Underground Natural Gas Storage Facility	1	7.0	2.0	50

			On-site Storage Capacity
	No. of Assets	Daily Production Rate (Dth)	Millions of Gallons	Dth
CenterPoint Energy
Propane Air-Gas Manufacturing Plant	13	231,000	13.5	1,187,000
LNG Plant Facility	1	72,000	12.0	1,000,000
CERC
Propane Air-Gas Manufacturing Plant	10	198,000	12.0	1,050,000
LNG Plant Facility	1	72,000	12.0	1,000,000

The table below reflects CenterPoint Energy’s and CERC’s NGD contracted upstream storage services as of December 31, 2019:

	Storage Capacity (Bcf)	Maximum Peak Daily Delivery (MMcf)
CenterPoint Energy
Upstream Storage Service	115	2,744
CERC
Upstream Storage Service	92	2,298

On an ongoing basis, CenterPoint Energy’s and CERC’s NGD 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 NGD has AMAs associated with their utility distribution service in Arkansas, Indiana, Louisiana, Mississippi, Oklahoma and Texas. The AMAs have varying terms, the longest of which expires in 2023. Pursuant to the provisions of the agreements, CenterPoint Energy’s and CERC’s NGD 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 NGD 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 NGD 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 NGD and to use the released capacity for other purposes when it is not needed for CenterPoint Energy’s and CERC’s NGD. CenterPoint Energy’s and CERC’s NGD may receive compensation from the asset manager through payments made over the life of the AMAs. CenterPoint Energy’s and CERC’s NGD has an obligation to purchase their winter storage requirements that have been released to the asset manager under these AMAs.

Assets

As of December 31, 2019, CenterPoint Energy’s and CERC’s NGD owned approximately 98,000 and 76,000 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 NGD 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

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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 NGD, 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 NGD 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.

Competition

CenterPoint Energy’s and CERC’s NGD 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 NGD’s facilities and market, sell and/or transport natural gas directly to commercial and industrial customers.

Energy Services (CenterPoint Energy and CERC)

CERC offers competitive variable and fixed-priced physical natural gas supplies primarily to commercial and industrial customers and electric and natural gas utilities through CES and its subsidiary, CEIP, collectively, Energy Services.

In 2019, CES marketed approximately 1,305 Bcf of natural gas (including approximately 47 Bcf to affiliates) and provided related energy services and transportation to approximately 31,000 customers in over 30 states. CES customers vary in size from small commercial customers to large utility companies. Not included in the 2019 customer count are approximately 66,000 natural gas customers that are served under residential and small commercial choice programs invoiced by their host utility. These customers are not included in customer count so as not to distort the significant margin impact from the remaining customer base.

CES offers a variety of natural gas management services to gas utilities, large industrial customers, electric generators, smaller commercial and industrial customers, municipalities, educational institutions, government facilities and hospitals. These services include load forecasting, supply acquisition, daily swing volume management, invoice consolidation, storage asset management, firm and interruptible transportation administration and forward price management. CES also offers a portfolio of physical delivery services designed to meet customers’ supply and risk management needs. These services include (1) through CEIP, permanent pipeline connections through interconnects with various interstate and intrastate pipeline companies and (2) through MES, temporary delivery of LNG and CNG throughout the lower 48 states, utilizing a fleet of customized equipment to provide continuity of natural gas service when pipeline supply is not available.

In addition to offering natural gas management services, CES procures and optimizes transportation and storage assets. CES maintains a portfolio of natural gas supply contracts and firm transportation and storage agreements to meet the natural gas requirements of its customers. CES aggregates supply from various producing regions and offers contracts to buy natural gas with terms ranging from one month to over five years. In addition, CES actively participates in the spot natural gas markets to balance daily and monthly purchases and sales obligations. Natural gas supply and transportation capabilities are leveraged through contracts for ancillary services including physical storage and other balancing arrangements.

As described above, CES offers its customers a variety of load following services. In providing these services, CES uses its customers’ purchase commitments to forecast and arrange its own supply purchases, storage and transportation services to serve customers’ natural gas requirements. As a result of the variance between this forecast activity and the actual monthly activity, CES will either have too much supply or too little supply relative to its customers’ purchase commitments. These supply imbalances arise each month as customers’ natural gas requirements are scheduled and corresponding natural gas supplies are nominated by CES for delivery to those customers. CES’s processes and risk control policy are designed to measure and value imbalances on a real-time basis to ensure that CES’s exposure to commodity price risk is kept to a minimum. The value assigned to these imbalances is calculated daily and is known as the aggregate VaR.

CenterPoint Energy’s and CERC’s risk control policy, which is overseen by CenterPoint Energy’s Risk Oversight Committee, defines authorized and prohibited trading instruments and trading limits. CES is a physical marketer of natural gas and uses a variety of tools, including pipeline and storage capacity, financial instruments and physical commodity purchase contracts, to support its sales. CES optimizes its use of these various tools to minimize its supply costs and does not engage in speculative commodity trading. CES currently operates within a VaR limit set by CenterPoint Energy’s Board of Directors, consistent with CES’ operational objective of matching its aggregate sales obligations (including the swing associated with load following services) with its supply portfolio in a manner that minimizes its total cost of supply. Should CES exceed this VaR limit, management is required to notify CenterPoint Energy’s Board of Directors.

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Assets

As of December 31, 2019, CEIP owned and operated over 210 miles of intrastate pipeline in Louisiana and Texas. In addition, CES leases transportation capacity on various interstate and intrastate pipelines and storage to service its shippers and end users.

Competition

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

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. The transaction is expected to close in the second quarter of 2020. For further information, see Notes 6 and 23 to the consolidated financial statements.

Infrastructure Services (CenterPoint Energy)

Infrastructure Services provides underground pipeline construction and repair services through wholly-owned subsidiaries Miller Pipeline, LLC and Minnesota Limited, LLC. Infrastructure Services provides services to many utilities, including CenterPoint Energy’s utilities, as well as other industries.

Backlog represents the amount of revenue Infrastructure Services expects to realize from work to be performed in the future on uncompleted contracts, including new contractual agreements on which work has not begun. Infrastructure Services operates primarily under two types of contracts, blanket contracts and bid contracts. Under blanket contracts, customers are not contractually committed to specific volumes of services; however, the Company expects to be chosen to perform work needed by a customer in a given time frame. These contracts are typically awarded on an annual or multi-year basis. For blanket work, backlog represents an estimate of the amount of revenue that Infrastructure Services expects to realize from work to be performed in the next twelve months on either existing contracts or contracts it reasonably expects to be renewed or awarded based upon recent history or discussions with customers. Under bid contracts, customers are contractually committed to a specific service to be performed for a specific price, whether in total for a project or on a per unit basis. 

Projects included in backlog can be subject to delays or cancellation as a result of regulatory requirements, adverse weather conditions and certain customer requirements, among other factors. Such delays or cancellations could cause realized revenue amounts to differ significantly from that which was originally expected.

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 is expected to close in the second quarter of 2020. For further information, see Notes 6 and 23 to the consolidated financial statements.

Midstream Investments (CenterPoint Energy)

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, 2019. 

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

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

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

Enable’s gathering and processing systems compete with gatherers and processors of all types and sizes, including those affiliated with various producers, other major pipeline companies and various independent midstream entities. 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 the principal elements of competition for its gathering and processing systems as gathering rate, processing value, system reliability, fuel rate, system run time, construction cycle time and prices at the wellhead.

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

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

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

Corporate and Other Operations (CenterPoint Energy and CERC)

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

CERC’s Corporate and Other Operations reportable segment consists primarily of corporate operations which support all of the business operations of CERC and includes unallocated corporate costs and inter-segment eliminations.

REGULATION

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, 2019.

Federal Energy Regulatory Commission

The FERC has jurisdiction under the NGA and the NGPA, as amended, to regulate the transportation of natural gas in interstate commerce and natural gas sales for resale in interstate commerce that are not first sales. The FERC regulates, among other things, the construction of pipeline and related facilities used in the transportation and storage of natural gas in interstate commerce, including the extension, expansion or abandonment of these facilities. The FERC 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 $1.29 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. CenterPoint Energy’s and CERC’s Energy Services reportable segment markets natural gas in interstate commerce pursuant to blanket authority granted by the FERC.

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

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has authority to impose significant civil penalties (up to approximately $1.29 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 the 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 is 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.

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

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 20 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 EECR 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.

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State and Local Regulation – Electric Generation (CenterPoint Energy)

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 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.

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

In almost all communities in which CenterPoint Energy’s and CERC’s NGD 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 10 to 30 years, although franchises in Arkansas are perpetual. CenterPoint Energy’s and CERC’s NGD expects to be able to renew expiring franchises. In most cases, franchises to provide natural gas utility services are not exclusive.

Substantially all of CenterPoint Energy’s and CERC’s NGD is subject to cost-of-service rate regulation by the relevant state public utility commissions and, in Texas, by those municipalities served by CenterPoint Energy’s and CERC’s NGD that have retained original jurisdiction. In certain of the jurisdictions in which they operate, CenterPoint Energy’s and CERC’s NGD 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 NGD’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.

Department of Transportation (CenterPoint Energy and CERC)

In December 2006, Congress enacted the 2006 Act, which reauthorized the programs adopted under the 2002 Act. These programs included several requirements related to ensuring pipeline safety, and a requirement to assess the integrity of pipeline transmission facilities in areas of high population concentration.

Pursuant to the 2006 Act, PHMSA, an agency of the DOT, issued regulations, effective February 12, 2010, requiring operators of gas distribution pipelines to develop and implement integrity management programs similar to those required for gas transmission pipelines, but tailored to reflect the differences in distribution pipelines. Operators of natural gas distribution systems were required to write and implement their integrity management programs by August 2, 2011. CenterPoint Energy’s and CERC’s natural gas distribution systems met this deadline.

Pursuant to the 2002 Act and the 2006 Act, PHMSA has adopted a number of rules concerning, among other things, distinguishing between gathering lines and transmission facilities, requiring certain design and construction features in new and replaced lines to reduce corrosion and requiring pipeline operators to amend existing written operations and maintenance procedures and operator qualification programs. PHMSA also updated its reporting requirements for natural gas pipelines effective January 1, 2011.

In December 2011, Congress passed the 2011 Act. This act increased the maximum civil penalties for pipeline safety administrative enforcement actions; required the DOT to study and report on the expansion of integrity management requirements and the sufficiency of existing gathering line regulations to ensure safety; required pipeline operators to verify their records on maximum allowable operating pressure; and imposed new emergency response and incident notification requirements. In 2016, the 2016 Act reauthorized PHMSA’s pipeline safety programs through 2019 and provided limited new authority, including the

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ability to issue emergency orders, to set inspection requirements for certain underwater pipelines and to promulgate minimum safety standards for natural gas storage facilities, as well as to provide increased transparency into the status of as-yet-incomplete PHMSA actions required by the 2011 Act. Congress did not pass a bill reauthorizing PHMSA in 2019, and PHMSA is operating under a continuing resolution until a new bill is passed. PHMSA did receive federal funding for fiscal year 2020.

CenterPoint Energy and CERC anticipate that compliance with PHMSA’s regulations, performance of the remediation activities by CenterPoint Energy’s and CERC’s NGD 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 of the 2011 and 2016 Acts, or implementation of future acts, by PHMSA 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.

Midstream Investments – Rate and Other Regulation (CenterPoint Energy)

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.

Interstate Natural Gas Pipeline Regulation

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

Market Behavior Rules; Posting and Reporting Requirements

The EPAct of 2005 amended the NGA and the FPA to add an anti-manipulation provision that makes it unlawful for any entity to engage in prohibited behavior as prescribed in FERC rules, which were subsequently issued in FERC Order No. 670. The EPAct of 2005 also amends the NGA, the FPA and the NGPA to give the FERC authority to impose civil penalties for violations of these statutes and FERC’s regulations, rules, and orders, of up to approximately $1.29 million per day per violation, subject to periodic adjustment to account for inflation. Should Enable fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, it could be subject to substantial penalties and fines. In addition, the CFTC is directed under the CEA to prevent price manipulations for the commodity and futures markets, including the energy futures markets. Pursuant to the Dodd-Frank Act and other authority, the CFTC has adopted anti-market manipulation regulations that prohibit fraud and price manipulation in the commodity and futures markets. The CFTC also has statutory authority to seek civil penalties of up to the greater of $1.2 million or triple the monetary gain to the violator for violations of the anti-market manipulation sections of the CEA. These maximum penalty levels are also subject to periodic adjustment to account for inflation.

Intrastate Natural Gas Pipeline and Storage Regulation

Intrastate natural gas transportation is largely regulated by the state in which the transportation takes place. However, an intrastate natural gas pipeline system may transport natural gas in interstate commerce provided that the rates, terms, and conditions of such transportation service comply with Section 311 of the NGPA and Part 284 of the FERC’s regulations. Rates for service pursuant to Section 311 of the NGPA are generally subject to review and approval by the FERC at least once every five years. Failure to observe the service limitations applicable to transportation services provided under Section 311, failure to comply with the rates approved by the FERC for Section 311 service, or failure to comply with the terms and conditions of service established in the pipeline’s FERC-approved Statement of Operating Conditions could result in the assertion of federal NGA jurisdiction by the FERC and/or the imposition of administrative, civil and criminal penalties, as described under “—Market Behavior Rules; Posting and Reporting Requirements” above.

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Natural Gas Gathering and Processing Regulation

Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of the FERC. Although the FERC has not made formal determinations with respect to all of the facilities Enable considers to be 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.

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.

Interstate Crude Oil Gathering Regulation

Enable’s crude oil gathering systems in the Williston Basin transport crude oil in interstate commerce pursuant to a public tariff in accordance with FERC regulatory requirements. 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 conferring any undue preference upon any shipper. FERC regulations also require interstate common carrier petroleum pipelines to file with the FERC and publicly post tariffs stating their interstate transportation rates and terms and conditions of service.

Intrastate Crude Oil and Condensate Gathering Regulation

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.

Safety and Health Regulation

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

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

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ENVIRONMENTAL MATTERS

The following discussion is based on environmental matters in the Registrants’ businesses as of December 31, 2019. 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:

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

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

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

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

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

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

• construct or acquire new facilities and equipment;

• acquire permits for facility operations or purchase emissions allowances;

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

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

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

The recent trend in environmental regulation has been to place 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 Registrants try to anticipate future regulatory requirements that might be imposed and plan accordingly to maintain compliance with changing environmental laws and regulations.

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.

Global Climate Change

There is increasing attention being paid in the United States and worldwide to the issue of climate change. As a result, from time to time, regulatory agencies have considered the modification of existing laws or regulations or the adoption of new laws or

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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, requires states to establish heat rate performance standards for steam electric generating facilities. Under the ACE rule, a state has three years to finalize its program and the EPA then has 18 months to approve, making compliance by Indiana Electric’s generating units required in 2023-2024.

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.

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 NGD could be adversely affected through lower natural gas sales and Enable’s natural gas gathering, processing and transportation and crude oil gathering businesses could experience lower revenues. 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 or tornadoes. 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.

Air Emissions

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 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 EPA has established new air emission control requirements for natural gas and NGLs production, processing and transportation activities. Under the NESHAPS, the EPA established the RICE MACT rule. Compressors and back up electrical generators used by CenterPoint Energy’s and CERC’s NGD, and back up electrical generators used by CenterPoint Energy and Houston Electric, are substantially compliant with these laws and regulations. Similarly, the EPA also established the MATS rule, which sets emission limits for mercury and other hazardous air pollutants from steam electric generating facilities. Indiana Electric’s generating units are in full compliance with the MATS rule.

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Water Discharges

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.

Waters of the United States

Under the Obama administration, the EPA promulgated a set of rules that included a comprehensive regulatory overhaul of defining “waters of the United States” for the purposes of determining federal jurisdiction. 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 released in January 2020 and will become final upon publication in the Federal Register. Environmental stakeholders and certain states have indicated their intent to challenge the new rule and further litigation is likely. The potential impact of any new “waters of the United States” regulations on the Registrants’ business, liabilities, compliance obligations or profits and revenues is uncertain at this time.

ELG

In 2015 the EPA finalized revisions to the existing steam electric wastewater discharge standards which set more stringent wastewater discharge limits and effectively prohibited further wet disposal of coal ash in ash ponds. These new standards are applied at the time of permit renewal and an affected facility must comply no later than December 31, 2023. In February 2019, the IURC approved Indiana Electric’s ELG compliance plan for its F.B. Culley Generating Station, and Indiana Electric is currently finalizing its ELG compliance plan for the remainder of its affected units as part of its ongoing IRP process.

Cooling Water Intake Structures

Section 316 of the federal Clean Water Act requires steam electric generating facilities use “best technology available” to minimize adverse environmental impacts on a body of water. In May 2014 EPA finalized a regulation requiring installation of BTA 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.

Hazardous Waste

The Registrants’ operations generate wastes, including some hazardous wastes, that are subject to the federal RCRA, and comparable state laws, which impose detailed requirements for the handling, storage, treatment, transport and disposal of hazardous and solid waste. RCRA currently exempts many natural gas gathering and field processing wastes from classification as hazardous waste. Specifically, RCRA excludes from the definition of hazardous waste waters produced and other wastes associated with the exploration, development or production of crude oil and natural gas. However, these oil and gas exploration and production wastes are still regulated under state law and the less stringent non-hazardous waste requirements of RCRA. Moreover, ordinary industrial wastes such as paint wastes, waste solvents, laboratory wastes and waste compressor oils may be regulated as hazardous waste. The transportation of natural gas in pipelines may also generate some hazardous wastes that would be subject to RCRA or comparable state law requirements.

Coal Ash

Indiana Electric has three ash ponds, two at the F.B. Culley facility (Culley East and Culley West) and one at the A.B. Brown facility. In 2015, the EPA finalized its CCR Rule, which regulates coal ash as non-hazardous material under the RCRA. The final rule allows beneficial reuse of ash, and the majority of the ash generated by Indiana Electric’s generating plants will continue to be reused. Under the existing CCR Rule, Indiana Electric is required to perform integrity assessments, including ground water monitoring, at its F.B. Culley and A.B. Brown generating stations. The ground water studies are necessary to determine the remaining service life of the ponds and whether a pond must be retrofitted with liners or closed in place. In March 2018, Indiana Electric began posting ground water data monitoring reports annually to its public website in accordance with the requirements of the CCR Rule. This data preliminarily 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,

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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 August 2020. Indiana Electric plans to seek extensions available under the CCR Rule that would allow Indiana Electric to continue to use the ponds through December 31, 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. For further discussion about Indiana Electric’s ash ponds, please see Note 16(e) to the consolidated financial statements.

Liability for Remediation

CERCLA, also known as “Superfund,” and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons responsible for the release of “hazardous substances” into the environment. Classes of PRPs include the current and past owners or operators of sites where a hazardous substance was released and companies that disposed or arranged for the disposal of hazardous substances at offsite locations such as landfills. Although petroleum, as well as natural gas, is expressly excluded from CERCLA’s definition of a “hazardous substance,” in the course of 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.

Liability for Preexisting Conditions

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

EMPLOYEES

The following table sets forth the number of employees by Registrant and reportable segment as of December 31, 2019:

	Number of Employees			Number of Employees Represented by Collective Bargaining Groups
Reportable Segment	CenterPoint Energy	Houston Electric	CERC	CenterPoint Energy	Houston Electric	CERC
Houston Electric T&D	2,768	2,768	—	1,424	1,424	—
Indiana Electric Integrated	443	—	—	221	—	—
Natural Gas Distribution	4,003	—	3,284	1,632	—	1,207
Energy Services	293	—	293	—	—	—
Infrastructure Services	4,345	—	—	3,850	—	—
Corporate and Other	2,410	—	—	178	—	—
Total	14,262	2,768	3,577	7,305	1,424	1,207

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

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 is expected to close in the second quarter of 2020. For further information, see Notes 6 and 23 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. The transaction is expected to close in the second quarter of 2020. For further information, see Notes 6 and 23 to the consolidated financial statements.

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INFORMATION ABOUT OUR EXECUTIVE OFFICERS

(as of February 25, 2020)

Name	Age	Title
Milton Carroll	69	Executive Chairman
John W. Somerhalder II	64	Interim President and Chief Executive Officer and Director
Xia Liu	50	Executive Vice President and Chief Financial Officer
Scott E. Doyle	48	Executive Vice President, Natural Gas Distribution
Kenneth M. Mercado	57	Senior Vice President, Electric Operations
Joseph J. Vortherms	59	Senior Vice President, Competitive Energy Businesses
Jason M. Ryan	44	Senior Vice President and General Counsel
Sue B. Ortenstone	63	Senior Vice President and Chief Human Resources Officer

Milton Carroll has served on the Board of Directors of CenterPoint Energy or its predecessors since 1992. He has served as Executive Chairman of CenterPoint Energy since June 2013 and as Chairman from September 2002 until May 2013. Mr. Carroll has served as a director of Halliburton Company since 2006. He has served as a director of Health Care Service Corporation since 1998 and as its chairman since 2002. He previously served as a director of Western Midstream Holdings, LLC, the general partner of Western Midstream Partners, LP, from February 2019 to August 2019, Western Gas Holdings, LLC, the general partner of Western Gas Partners, LP, from 2008 to February 2019, LyondellBasell Industries N.V. from July 2010 to July 2016 as well as LRE GP, LLC, the general partner of LRR Energy, L.P., from November 2011 to January 2014.

John W. Somerhalder has served as Interim President and Chief Executive Officer of CenterPoint Energy since February 19, 2020. He has served as a director of CenterPoint Energy since October 2016. He most recently served as Interim President and Chief Executive Officer of Colonial Pipeline Company, a privately held company that operates a refined liquid petroleum products pipeline system, from February 2017 to October 2017. Prior to joining Colonial Pipeline Company, Mr. Somerhalder served as President, Chief Executive Officer and as a director of AGL Resources Inc., a former publicly traded energy services holding company, whose principal business is the distribution of natural gas, from March 2006 through December 2015 and as chairman of the board of AGL Resources Inc. from November 2007 through December 2015. Prior to joining AGL Resources Inc., he served in a number of roles with El Paso Corporation, a publicly traded natural gas and related energy products provider, and its subsidiaries since 1977, including as Executive Vice President. Mr. Somerhalder currently serves on the board of directors of Enable GP, LLC, the general partner of Enable Midstream Partners, LP. He served as a director of Crestwood Equity GP LLC, the general partner of Crestwood Equity Partners LP, from 2013 to February 2020 and as a director of SunCoke Energy Partners GP LLC, the general partner of SunCoke Energy Partners, L.P. from 2017 to July 2019. He also serves as a director or trustee on the boards of numerous non-profit organizations.

Xia Liu has served as Executive Vice President and Chief Financial Officer of CenterPoint Energy since April 2019. Prior to joining CenterPoint Energy, Ms. Liu was Executive Vice President, Chief Financial Officer and Treasurer of Georgia Power Company, a subsidiary of the Southern Company, from October 2017 to April 2019 and served as Vice President, Chief Financial Officer and Treasurer of Gulf Power Company, formerly a subsidiary of the Southern Company, from July 2015 to October 2017. She also served in various finance, regulatory and operations roles of increasing responsibility at the Southern Company beginning in 1998, including Senior Vice President, Finance and Treasurer from 2014 to 2015 and Vice President, Finance and Assistant Treasurer from 2010 to 2014. Ms. Liu currently serves on the Board of Directors of Enable GP, LLC, the general partner of Enable Midstream Partners, LP, and as a director of the PACT World Organization.

Scott E. Doyle has served as Executive Vice President, Natural Gas Distribution since February 2019. With more than 25 years of utility industry experience, he previously served as Senior Vice President, Natural Gas Distribution from March 2017 to February 2019; Senior Vice President, Regulatory and Public Affairs from February 2014 to March 2017; as Division Vice President, Rates and Regulatory from April 2012 to February 2014; and as Division Vice President, Regional Operations from March 2010 to April 2012. Mr. Doyle currently serves on the boards of Goodwill Industries of Houston, Southern Gas Association, Central Indiana Corporate Partnership, Evansville Regional Business Council and the American Gas Foundation. He previously served on the boards of the Texas Gas Association and the Association of Electric Companies of Texas.

Kenneth M. Mercado has served as Senior Vice President, Electric Operations since February 2020. He previously served as Chief Integration Officer from May 2018 to February 2020; as Senior Vice President, Electric Operations from February 2014 to May 2018; and as Division Senior Vice President, Grid and Market Operations from January 2012 to February 2014 in addition to other key positions at CenterPoint Energy focusing on Electric Operations technology and logistics. Mr. Mercado serves on the boards of the Southeastern Electric Exchange, Research Advisory Counsel at the Electric Power Research Institute, Advisory

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Board at Texas A&M Smart Grid Coalition, the Engineering Leadership Board at the University of Houston and the Center for Houston’s Future.

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

Jason M. Ryan has served as Senior Vice President and General Counsel since April 2019. He previously served as Senior Vice President, Legal, Regulatory Services and Government Affairs from February 2019 to April 2019; as Vice President of Regulatory and Government Affairs and Associate General Counsel from March 2017 to February 2019; and as Vice President and Associate General Counsel from September 2014 to March 2017. He was appointed to the Texas Diabetes Council by Texas Governor Perry in 2013 for a term ending in 2019 and reappointed by Texas Governor Abbott in 2019 for a term ending in 2025. Mr. Ryan currently serves on the boards of the Houston Bar Foundation, the Texas Gulf Coast Chapter of the Leukemia & Lymphoma Society and the Association of Electric Companies of Texas. He also serves on the executive committee of the legal committee of the American Gas Association.

Sue B. Ortenstone has served as Senior Vice President and Chief Human Resources Officer of CenterPoint Energy since February 2014. Prior to joining CenterPoint Energy, Ms. Ortenstone was Senior Vice President and Chief Administrative Officer at Copano Energy from July 2012 to May 2013. Before joining Copano, she spent more than 30 years at El Paso Corporation and served most recently as Senior Vice President and then Executive Vice President and Chief Administrative Officer from November 2003 to May 2012. Ms. Ortenstone serves on the Industrial Advisory Board in the College of Engineering at the University of Wisconsin. Ms. Ortenstone also serves on the Board of Trustees for Northwest Assistance Ministries of Houston.

Item 1A. Risk Factors

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 results to differ from those indicated in any forward-looking statement or projection contained in this combined report on Form 10-K, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Certain Factors Affecting Future Earnings” in Item 7, which should be read in conjunction with the risk factors contained in this Item 1A. Carefully consider each of the risks described below, including those relating to Houston Electric and CERC, which, along with CenterPoint Energy, are collectively referred to as the Registrants. Unless the context indicates otherwise, where appropriate, information relating to a specific registrant has been segregated and labeled as such and specific references to Houston Electric and CERC in this section also pertain to CenterPoint Energy. In this combined report on Form 10-K, the terms “our,” “we” and “us” are used as abbreviated references to CenterPoint Energy, Inc. together with its subsidiaries.

Risk Factors Associated with Our Consolidated Financial Condition

CenterPoint Energy is a holding company with no operations or operating assets of its own. As a result, CenterPoint Energy depends on the performance of and distributions from its subsidiaries and from Enable to meet its payment obligations and to pay dividends on its common and preferred stock, and provisions of applicable law or contractual restrictions could limit the amount of those distributions.

CenterPoint Energy derives all of its operating income from, and holds all of its assets through, its subsidiaries, including its interests in Enable. As a result, CenterPoint Energy depends on 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. For a description of these restrictions and further information on ring-fencing measures that may adversely affect CenterPoint Energy’s ability to receive dividends from Houston Electric as well as other financial impacts, please read “—The imposition of certain

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ring-fencing measures at Houston Electric could adversely affect CenterPoint Energy’s cash flows, credit quality, financial condition and results of operations.”

Additionally, CenterPoint Energy’s results of operations, future growth and earnings and dividend goals depend on the performance of its utility and non-utility (such as CES, Infrastructure Services and ESG) subsidiaries which contribute to a portion of its consolidated earnings and which may not perform at expected or forecasted levels or do not achieve the projected growth in these businesses as anticipated. As part of their non-utility businesses, CenterPoint Energy and CERC also offer home repair protection plans to natural gas customers in Texas and Louisiana (through a third-party provider) and provide home appliance maintenance and repair services to customers in Minnesota. For a discussion of risks that may impact the amount of cash distributions CenterPoint Energy receives with respect to its interests in Enable, please read “— Additional Risk Factors Affecting CenterPoint Energy’s Interests in Enable Midstream Partners, LP — CenterPoint Energy’s cash flows will be adversely impacted if it receives less cash distributions from Enable than it currently expects.”

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.

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

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 and/or preferred stock by CenterPoint Energy. We may also use such sources to refinance any outstanding indebtedness as it matures. As of December 31, 2019, CenterPoint Energy had $15.1 billion of outstanding indebtedness on a consolidated basis, which includes $977 million of non-recourse Securitization Bonds. For information on maturities through 2024, see Note 14 to the consolidated financial statements. Our future financing activities may be significantly affected by, among other things:

• general economic and capital market conditions;

• credit availability from financial institutions and other lenders;

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

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

• the future performance of our and Enable’s businesses;

• integration of Vectren’s businesses into CenterPoint Energy;

• maintenance of acceptable credit ratings;

• market expectations regarding our future earnings and cash flows;

• our ability to access capital markets on reasonable terms;

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

• provisions of relevant tax and securities laws.

As of December 31, 2019, Houston Electric had approximately $4.0 billion aggregate principal amount of general mortgage bonds outstanding under the General Mortgage, including approximately $68 million held in trust to secure pollution control bonds for which CenterPoint Energy is obligated. Additionally, as of December 31, 2019, Houston Electric had approximately $102 million aggregate principal amount of first mortgage bonds outstanding under the Mortgage. Houston Electric may issue additional general mortgage bonds on the basis of retired bonds, up to 70% of property additions or cash deposited with the trustee. As of December 31, 2019, approximately $3.7 billion of additional first mortgage bonds and general mortgage bonds in the aggregate could be issued on the basis of retired bonds and 70% of property additions as of December 31, 2019. However, Houston Electric

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has contractually agreed that it will not issue additional first mortgage bonds, subject to certain exceptions. As of December 31, 2019, SIGECO had approximately $293 million aggregate principal amount of first mortgage bonds outstanding. SIGECO may issue additional bonds under its Mortgage Indenture up to 60% of currently unfunded property additions. As of December 31, 2019, approximately $1.1 billion of additional first mortgage bonds could be issued on this basis. However, under certain circumstances Indiana Electric is limited in its ability to issue additional bonds under the Mortgage Indenture due to a provision in its parent’s, VUHI, indentures.

The Registrants’ current credit ratings and any changes in credit ratings in 2019 and to date in 2020 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.

The imposition of certain ring-fencing measures at Houston Electric could adversely affect CenterPoint Energy’s cash flows, credit quality, financial condition and results of operations.

As part of its most recent base rate proceeding, Houston Electric has agreed, as part of a settlement, to certain “ring-fencing” measures to increase its financial separateness from CenterPoint Energy. As part of the Stipulation and Settlement Agreement, Houston Electric and CenterPoint Energy are subject to various ring-fencing measures. For further information about the Stipulation and Settlement Agreement, please 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, further ring-fencing measures could be imposed on Houston Electric in the future through legislation or PUCT rules or orders. As a result of such ring-fencing measures, CenterPoint Energy’s cash flows, credit quality, financial condition and results of operations could be materially adversely affected.

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

The LIBOR is the basic rate of interest widely used as a global reference for setting interest rates on variable rate loans and other securities. Each of the Registrants’ credit and term loan facilities, including certain facilities or financial instruments entered into by their subsidiaries, use LIBOR as a reference rate. On July 27, 2017, the Financial Conduct Authority in the United Kingdom announced that it would phase out LIBOR as a benchmark by the end of 2021. It is unclear whether new methods of calculating LIBOR will be established such that it continues to exist after 2021. If LIBOR reference rates become unavailable, any LIBOR borrowings under the Registrants’ credit and term loan facilities would convert at the end of the applicable interest period to alternate base rate loans and any future borrowings thereunder would be made as alternate base rate loans. Alternate base rate loans generally constitute a higher cost of capital.

Certain of CenterPoint Energy’s credit and term loan facilities provide for a mechanism to amend such facility to reflect the establishment of an alternative reference rate upon the inability to determine the LIBOR-based Eurodollar rate or occurrence of certain events related to the phase-out of LIBOR. However, we have not yet pursued any technical amendment or other contractual alternative to address this matter and are currently evaluating the impact of the potential replacement or unavailability of the LIBOR interest rate. In addition, the overall financial markets may be disrupted as a result of the phase-out or replacement of LIBOR. Uncertainty as to the nature of such potential phase-out and alternative reference rates or disruption in the financial markets could have a material adverse effect on our financial condition, results of operations and cash flows.

An impairment of goodwill, long-lived assets, including intangible assets, equity method investments and an impairment or fair value adjustment to CenterPoint Energy’s Enable Series A Preferred Unit investment could reduce our earnings.

Goodwill is recorded when the purchase price of a business exceeds the fair market value of the tangible and separately measurable intangible net assets. Accounting principles generally accepted in the United States of America require CenterPoint Energy to test goodwill for impairment on an annual basis or when events or circumstances occur indicating that goodwill might be impaired. Long-lived assets, including intangible assets with finite useful lives, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. As a result of the Merger, CenterPoint Energy has increased the amount of goodwill and other intangible assets on its consolidated financial statements that are subject to impairment based on future adverse changes to the acquired businesses or general market conditions.

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In connection with its preparation of financial statements for the year ended December 31, 2019, CenterPoint Energy and CERC, as applicable, identified triggering events for interim goodwill impairment tests at their Infrastructure Services and Energy Services reporting units. Early stage bids received from market participants during the exploration of strategic alternatives for these businesses at year-end indicated that the carrying value of each reporting unit was more likely than not below the fair value. As a result, CenterPoint Energy and CERC evaluated long-lived assets, including property, plant and equipment, and specifically identifiable intangibles subject to amortization, for recoverability and the goodwill within the reporting units was tested for impairment as of December 31, 2019. The long-lived assets within the Infrastructure Services and Energy Services reporting units were determined to be recoverable based on undiscounted cash flows, considering the likelihood of possible outcomes existing as of December 31, 2019, including the assessment of the likelihood of a future sale of these assets.

CenterPoint Energy and CERC recognized an impairment loss of $48 million, the amount by which the carrying value (inclusive of deferred income tax liabilities of $25 million) of their respective Energy Services reporting unit exceeded fair value as of December 31, 2019. Following the impairment, the carrying value of the goodwill remaining in the Energy Services reporting unit is $62 million as of December 31, 2019. CenterPoint Energy did not recognize any impairments on its Infrastructure Services reporting unit in 2019.

On February 3, 2020, CenterPoint Energy, through its subsidiary VUSI, entered into the Securities Purchase Agreement to sell the businesses within its Infrastructure Services reporting unit. As a result, certain assets and liabilities representing a business within this reporting unit that will be transferred under the Securities Purchase Agreement (the “Disposal Group”) met the held for sale criteria during the first quarter of 2020. Because the transaction is structured as an asset sale for income tax purposes, the Disposal Group will exclude the deferred tax liabilities. CenterPoint Energy anticipates recording an impairment loss on assets held for sale of approximately $85 million, plus an additional loss for transaction costs, in the first quarter of 2020. The actual amount of the impairment or loss may be materially different from the preliminary amount.

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 reporting unit. Certain assets and liabilities representing a business within this reporting unit that will be transferred under the Equity Purchase Agreement (the “Disposal Group”) met the held for sale criteria during the first quarter of 2020. Because the transaction is structured as an asset sale for income tax purposes, the Disposal Group will exclude the deferred tax liabilities and certain assets and liabilities within the reporting unit that will be retained by CenterPoint Energy and CERC upon closing. CenterPoint Energy and CERC anticipate recording an impairment loss, consisting of both goodwill and long-lived asset impairments, on assets held for sale of approximately $80 million, plus an additional loss for transaction costs, in the first quarter of 2020. The actual amount of the impairment or loss may be materially different from the preliminary amount.

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. For example, if Enable’s common unit price, distributions or earnings were to decline, and that decline is deemed to be other than temporary, CenterPoint Energy could determine that it is unable to recover the carrying value of its equity investment in Enable. Considerable judgment is used in determining if an impairment loss is other than temporary and the amount of any impairment. Such an impairment occurred during the year ended December 31, 2015 due to the sustained low Enable common unit price and further declines in such price that year, among other factors impacting the midstream oil and gas industry. As of December 31, 2019, CenterPoint Energy’s total investment in Enable is $10.29 per unit and Enable’s common unit price closed at $10.03 per unit (approximately $61 million below carrying value). Based on an analysis of its investment in Enable as of December 31, 2019, CenterPoint Energy believes that the decline in the value of its investment is temporary, and that the carrying value of its investment of $2.4 billion will be recovered. On February 24, 2020, Enable’s common unit price closed at $7.63 (approximately $622 million below carrying value). A sustained low Enable common unit price could result in CenterPoint Energy again recording impairment charges in the future.

For investments CenterPoint Energy accounts for as investments without a readily determinable fair value, such as the Enable Series A Preferred Unit investment, the carrying value of the asset may be adjusted to fair value, resulting in a gain or loss in the period, if a transaction on an identical or similar investment in Enable is observed. Additionally, CenterPoint Energy considers qualitative impairment triggers, such as significant deterioration in earnings performance, significant decline in market condition and other factors that raise significant concerns about Enable’s ability to continue as a going concern, to determine if an impairment analysis should be performed on its investment.

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

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

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, each of these factors could adversely affect our results of operations, liquidity and financial position.

CenterPoint Energy, through Infrastructure Services, also contributes to several multi-employer pension plans. If Infrastructure Services withdraws from these plans, CenterPoint Energy may be required to pay an amount based on the allocable share of the plans’ unfunded vested benefits, referred to as the withdrawal liability. This could adversely affect our results of operations, liquidity and financial position.

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

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

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

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

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

CenterPoint Energy has approximately $828 million principal amount of ZENS outstanding as of December 31, 2019. 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 ($75 million in the aggregate, or $5.28 per ZENS, as of December 31, 2019) 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 continues to increase by the amount of the tax benefit realized each year. If the ZENS had been redeemed on December 31, 2019, deferred taxes of approximately $429 million would have been payable in 2019, based on 2019 tax rates in effect. In addition, if all the shares of ZENS-Related Securities had been sold on December 31, 2019 to fund the aggregate redemption amount, capital gains taxes of approximately $149 million would have been payable in 2019. 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

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or from other sources, ZENS exchanges result in a cash outflow because tax deferrals related to the ZENS and ZENS-Related Securities shares would typically cease when ZENS are exchanged and ZENS-Related Securities shares are sold.

Dividend requirements associated with the Series A Preferred Stock and the Series B Preferred Stock that CenterPoint Energy issued to fund a portion of the Merger subject it to certain risks.

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. Any future payments of cash dividends, and the amount of any cash dividends CenterPoint Energy pays, on the Series A Preferred Stock and the Series B 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 and the Series B Preferred Stock when due 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.

The terms of the Series A Preferred Stock and the Series B Preferred Stock further 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.

Risk Factors Affecting Electric Generation, Transmission and Distribution Businesses (CenterPoint Energy and Houston Electric)

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

Houston Electric’s rates are regulated by certain municipalities and the PUCT and Indiana Electric’s rates are regulated by the IURC. Their rates are set in comprehensive base rate proceedings (i.e., general rate cases) based on an analysis of their invested capital, their expenses and other factors in a designated test year. Each of these rate proceedings is subject to third-party intervention and appeal, and the timing of a general base rate proceeding may be out of Houston Electric’s and Indiana Electric’s control. For Houston Electric, a general base rate proceeding is required 48 months from the date of the order setting rates in its most recent comprehensive rate proceeding, unless the PUCT issues an order extending the deadline to file that general base rate proceeding. For Indiana Electric, a general base rate proceeding is required prior to the expiration of its TDSIC plan, which expires on December 31, 2023. Houston Electric and Indiana Electric can make no assurance that their respective base rate proceedings will result in favorable adjustments to their rates, in full cost recovery or approval of other requested items, including, among other things, capital structure and ROE. Moreover, these base rate proceedings have caused in certain instances, and in the future could cause, Houston Electric and Indiana Electric to recover their investments below their requested levels, below the national average for utilities or below recently approved levels for other utilities in their respective jurisdictions.

For instance, on April 5, 2019, Houston Electric filed its base rate application with the PUCT and the cities in its service area to change its rates, seeking approval for revenue increases of approximately $194 million, excluding a rider to refund approximately $40 million annually over three years. This rate filing was based on a rate base of $6.4 billion, a 50% debt/50% equity capital structure and a 10.4% ROE. Houston Electric also requested a prudency determination on all capital investments made since January 1, 2010; the establishment of a rider to refund approximately $119 million to its customers over three years resulting from the TCJA; updated depreciation rates; and approval to clarify and update various non-rate tariff provisions. After a five-day hearing in June 2019, and following the issuance of a PFD by the administrative law judges who heard the case, the parties entered into a Stipulation and Settlement Agreement. On February 14, 2020, the PUCT approved the Stipulation and Settlement Agreement, which established rates based on a $13 million increase in annual revenues, a capital structure of 42.5% equity/57.5% debt and a 9.4% ROE. The Stipulation and Settlement Agreement requires Houston Electric to file another case within 48 months of the final order and removes the possibility that the deadline would be extended. For more information on Houston Electric’s base rate case, please read “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.

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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. 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 Houston Electric, the DCRF mechanism adjusts an electric utility’s rates for increases in net distribution-invested capital (e.g., distribution plant and distribution-related intangible plant and communication equipment) since its last comprehensive base rate proceeding, but Houston Electric may only make a DCRF filing once per calendar year and not during a comprehensive base rate proceeding. In connection with the Stipulation and Settlement Agreement, Houston Electric agreed not to file its DCRF in 2020. The TCOS mechanism allows a transmission service provider to update its wholesale transmission rates to reflect changes in transmission-related invested capital, but is only available to Houston Electric twice per calendar year. However, neither of these mechanisms provides for recovery of operations and maintenance expenses.

Similarly, for Indiana Electric, the TDSIC rate mechanism allows electric utilities (that have an IURC-approved seven-year infrastructure improvement plan) to request incremental rate increases every six months to pay for the projects included in that plan, subject to IURC approval. However, the TDSIC allows the utility to recover 80% of the costs as they are incurred, with the remaining costs to be deferred as regulatory assets to be recovered in the next base rate case. TDSIC rate increases are limited to no more than 2% of the utility’s total retail revenues from the prior year. Indiana Electric recovers transmission costs through a FERC-approved formula rate and reflects charges and costs associated with participation in MISO through the MCRA mechanism, which is filed annually. Other non-fuel purchased power costs are recovered annually via the RCRA Mechanism. Electricity suppliers are required to submit energy efficiency plans to the IURC at least once every three years. Indiana Electric recovers program and administrative costs of these plans, including lost revenues and financial incentives, via its annual DSMA mechanism. The DSMA is subject to IURC approval.

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 the rate mechanisms discussed above, the regulatory process by which rates are determined is subject to change as a result of the legislative process or rulemaking, as the case may be, and may not always be available or result in rates that will produce recovery of Houston Electric’s and Indiana Electric’s costs or enable them to earn an expected return. In addition, changes to the interim adjustment mechanisms could result in an increase in regulatory lag or otherwise impact Houston Electric’s 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.

Unlike Houston Electric, Indiana Electric must seek approval by the IURC for long-term financing authority and by the FERC for its short-term financing authority. This authority allows Indiana Electric the flexibility to enter into various financing arrangements. In the event that the IURC or the FERC do not approve Indiana Electric’s financing authority, Indiana Electric may not be able to fully execute its financing plans and its financial condition, results of operations and cash flows could be materially adversely affected.

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

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

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

A significant portion of Houston Electric’s revenues is derived from rates that it collects from each REP based on the amount of electricity it delivers on behalf of such REP. Similarly, Indiana Electric’s revenues are derived from rates it charges its customers to provide electricity. Houston Electric’s and Indiana Electric’s revenues and results of operations are subject to seasonality, weather conditions and other changes in electricity usage. 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.

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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.

Indiana Electric’s execution of its IRP and its regulated power supply operations are subject to various risks, including timely recovery of capital investments, increased costs and facility outages or shutdowns.

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 projects that the lowest cost and least risk generation portfolio to serve customers over the next 20 years involves 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 filed a petition seeking authorization from the IURC to construct a new 700-850 MW natural gas combined cycle generating facility to replace certain existing generation capacity at an approximate cost of $900 million, which included the cost of a new natural gas pipeline to serve the facility, among other things. While the IURC approved the construction of a 50 MW universal solar array and the plan to retrofit its largest, most efficient coal-fired generation unit (Culley Unit 3), the IURC denied Indiana Electric’s request to construct a 700-850 MW natural gas combined cycle generating facility. The IURC urged Indiana Electric to utilize its next IRP planning cycle to evaluate the merits of a more diverse generation portfolio.

During the 2019 Indiana legislative session, certain proposed legislation would have prohibited the construction of new generation assets 250 MW or larger until 2021, among other prohibitions, by directing the IURC to not issue any final orders in proceedings requesting such construction. Although this proposed legislation was ultimately defeated, a similar moratorium on the construction of new generation assets in Indiana could be reintroduced in a subsequent legislative session. Legislation has been proposed in 2020 that would require IURC approval to retire coal-fired generation. This legislation, by its terms, would sunset in early 2021 and is not expected to impact Indiana Electric as currently drafted.

With respect to its upcoming IRP, Indiana Electric has conducted a request for proposals targeting 10 to 700 MW of capacity and unit-contingent energy and anticipates filing its 2019/2020 IRP in mid-2020. 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 the proposed moratorium in 2019 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.

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 relies on coal for substantially all of its generation capacity. Currently, its coal supply is purchased largely from a single, unrelated party and, although the coal supply is under long-term contract, the loss of this supplier or transportation interruptions could adversely affect Indiana Electric’s results of operations, financial condition and cash flows.

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

Houston Electric and Indiana Electric are members of ERCOT and MISO, respectively, which serve the electric transmission needs of their applicable regions. As a result of their respective participation in ERCOT and MISO, Houston Electric and Indiana Electric do not have operational control over their transmission facilities and are subject to certain costs for improvements to these regional electric transmission systems. In addition, the FERC has jurisdiction with respect to ensuring the reliability of electric transmission service, including transmission facilities owned by Houston Electric and other utilities within ERCOT and Indiana Electric and other utilities within MISO, respectively. The FERC has designated the NERC as the ERO to promulgate standards,

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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.

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

Houston Electric’s receivables from the distribution of electricity are collected from REPs that supply the electricity Houston Electric distributes to their customers. As of December 31, 2019, Houston Electric did business with approximately 68 REPs. Adverse economic conditions, structural problems in the market served by ERCOT or financial difficulties of one or more REPs could impair the ability of these REPs to pay for Houston Electric’s services or could cause them to delay such payments. Houston Electric depends on these REPs to remit payments on a timely basis. Applicable regulatory provisions require that customers be shifted to another REP or a provider of last resort if a REP cannot make timely payments. Applicable PUCT regulations significantly limit the extent to which Houston Electric can apply normal commercial terms or otherwise seek credit protection from firms desiring to provide retail electric service in its service territory, and Houston Electric thus remains at risk for payments related to services provided prior to the shift to another REP or the provider of last resort. A significant portion of Houston Electric’s billed receivables from REPs are from affiliates of NRG and Vistra Energy Corp., formerly known as TCEH Corp. Houston Electric’s aggregate billed receivables balance from REPs as of December 31, 2019 was $192 million. Approximately 32% and 12% of this amount was owed by affiliates of NRG and Vistra Energy Corp., respectively. Any delay or default in payment by REPs could adversely affect Houston Electric’s cash flows, financial condition and results of operations. If a REP were unable to meet its obligations, it could consider, among various options, restructuring under the bankruptcy laws, in which event such REP might seek to avoid honoring its obligations, and claims might be made by creditors involving payments Houston Electric had received from such REP.

Risk Factors Affecting Natural Gas Distribution and Competitive Energy Services Businesses (CenterPoint Energy and CERC)

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. The transaction is expected to close in the second quarter of 2020. For further information, see Notes 6 and 23 to the consolidated financial statements.

Rate regulation of NGD may delay or deny its ability to earn an expected return and fully recover its costs.

NGD’s rates are regulated by certain municipalities (in Texas only) and state commissions based on an analysis of NGD’s invested capital, expenses and other factors in a test year (often either fully or partially historic) in comprehensive base rate proceedings, subject to periodic review and adjustment. Each of these proceedings is subject to third-party intervention and appeal, and the timing of a general base rate proceeding may be out of NGD’s control. NGD has pending, or anticipates the filing of, rate cases in Indiana, Minnesota and Texas during 2020. NGD 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 NGD 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 NGD is allowed to charge may not match its costs at any given time, resulting in what is referred to as “regulatory lag.” Though several interim rate adjustment mechanisms have been approved by jurisdictional regulatory authorities and implemented by NGD to reduce the effects of regulatory lag, such adjustment mechanisms are subject to the applicable regulatory body’s approval, which we cannot assure would be approved, and are subject to certain limitations that may reduce or otherwise impede NGD’s ability to adjust its rates or result in rates below those requested by NGD.

Arkansas allows public utilities to elect to have their rates regulated pursuant to a FRP, providing for a utility’s base rates to be adjusted once a year. In each of Louisiana, Mississippi and Oklahoma, NGD makes annual filings utilizing various formula rate mechanisms that adjust rates based on a comparison of authorized return to actual return to achieve the allowed return rates in those jurisdictions. Additionally, in Minnesota, the MPUC implemented a full revenue decoupling program, which separates approved revenues from the amount of natural gas used by its customers. Further, in Indiana, NGD may file a CSIA every six months to seek rate increases to recover certain federally mandated project costs (e.g., pipeline safety). The TDSIC (recovered

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through the CSIA), allows the utility to recover 80% of its project costs associated with an IURC-approved seven-year infrastructure improvement plan as they are incurred, with the remaining costs to be deferred until the next base rate case, and rate increases are limited to no more than 2% of the utility’s total retail revenues. In Ohio, the DRR is an annual mechanism that allows a utility to recover its investments in utility plant and operating expenses associated with replacing bare steel and cast-iron pipelines, as well as certain other infrastructure investments. The effectiveness of these filings and programs depends on the approval of the applicable state regulatory body.

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

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

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.

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

NGD 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 NGD’s natural gas supply is purchased from intrastate and interstate pipelines. If NGD is unable to secure an independent natural gas supply of its own or through its affiliates or if third-party service providers fail to timely deliver natural gas to meet NGD’s requirements, the resulting decrease in natural gas supply in NGD’s service territories could have a material adverse effect on its results of operations, cash flows and financial condition. Additionally, a significant disruption, whether through reduced intrastate and interstate pipeline transmission or storage capacity or other events affecting natural gas supply, including, but not limited to, operational failures, hurricanes, tornadoes, floods, acts of terrorism or cyber-attacks or changes in legislative or regulatory requirements, could also adversely affect NGD’s businesses. Further, to the extent that NGD’s natural gas requirements cannot be met through access to or continued use of existing natural gas infrastructure or if additional infrastructure, including onshore and offshore exploration and production facilities, gathering and processing systems and pipeline and storage capacity is not constructed at a rate that satisfies demand, then NGD’s operations could be negatively affected.

NGD and CES are subject to fluctuations in notional natural gas prices as well as geographic and seasonal natural gas price differentials, which could affect the ability of their suppliers and customers to meet their obligations or otherwise adversely affect their liquidity, results of operations and financial condition.

NGD and CES are subject to risk associated with changes in the notional price of natural gas as well as geographic and seasonal natural gas price differentials that impact their businesses, including transportation and storage, whether through the use of AMAs or other arrangements. Increases in natural gas prices might affect NGD’s and CES’s ability to collect balances due from their customers and, for NGD, 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 NGD and CES operate, thereby resulting in decreased sales and revenues and (ii) increase the risk that NGD’s and CES’s 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. Additionally, a decrease in natural gas prices could increase the amount of collateral required under hedging arrangements. AMAs may be subject to regulatory approval, and such agreements may not be renewed or may be renewed with less favorable terms.

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

If CERC’s credit rating were to decline, it might be required to post cash collateral under its shipping or hedging arrangements or to purchase natural gas. If a credit rating downgrade and the resultant cash collateral requirement were to occur at a time when CERC was experiencing significant working capital requirements or otherwise lacked liquidity, CERC’s results of operations, financial condition and cash flows could be adversely affected.

NGD’s and CES’s revenues and results of operations are seasonal.

NGD’s and CES’s revenues are primarily derived from natural gas sales. Thus, their revenues and results of operations are subject to seasonality, weather conditions and other changes in natural gas usage, with revenues being higher during the winter months. As in certain past years, unusually mild weather in the winter months could diminish our results of operations and harm our financial condition. Conversely, as occurred in certain past years, extreme cold weather conditions could increase our results of operations in a manner that would not likely be annually recurring.

The states in which NGD provides service may, either through legislation or rules, adopt restrictions regarding organization, financing and affiliate transactions that could have significant adverse impacts on NGD’s ability to operate.

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

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

NGD and CES must compete with alternate energy sources, which could result in less natural gas marketed and have an adverse impact on our results of operations, financial condition and cash flows.

NGD and CES compete 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 NGD and CES 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 NGD’s facilities and market, sell and/or transport natural gas directly to commercial and industrial customers. Any reduction in the amount of natural gas marketed, sold or transported by NGD and CES as a result of competition may have an adverse impact on our results of operations, financial condition and cash flows.

Infrastructure Services’ and ESG’s operations could be adversely affected by a number of factors.

Infrastructure Services’ and ESG’s business results are dependent on a number of factors. The industries are competitive and many of the contracts are subject to a bidding process. Should Infrastructure Services and ESG be unsuccessful in bidding contracts (e.g., federal Indefinite Delivery/Indefinite Quantity contracts for ESG), 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 Infrastructure Services or ESG operate could adversely impact operating results.

Infrastructure Services enters into a variety of contracts, some of which are fixed price. Other risks that could adversely affect Infrastructure Services include, but are not limited to: failure to properly construct pipeline infrastructure; loss of significant customers or a significant decline in related customer revenues; cancellation of projects by customers and/or reductions in the scope of the projects; changes in the timing of projects; the inability to obtain materials and equipment required to perform services from suppliers and manufacturers; and changes in the market prices of oil and natural gas and state regulatory requirements that mandate pipeline replacement programs that would affect the demand for infrastructure construction and/or the project margin realized on projects. For ESG, other risks include, but are not limited to: discontinuation of the federal ESPC and UESC programs;

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the inability of customers to finance projects; failure to appropriately design, construct or operate projects; and cancellation of projects by customers and/or reductions in the scope of the projects.

In addition, Infrastructure Services has supported CenterPoint Energy’s utilities pursuant to service contracts. In most instances, the ability to maintain these service contracts depends upon regulatory discretion, and there can be no assurance it will be able to obtain future service contracts, or that existing arrangements will not be revisited.

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 is expected to close in the second quarter of 2020. For further information, see Notes 6 and 23 to the consolidated financial statements.

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

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 guaranties do not represent incremental consolidated obligations; rather, they represent parental guaranties 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 guaranties.

Risk Factors Affecting CenterPoint Energy’s Interests in Enable Midstream Partners, LP (CenterPoint Energy)

CenterPoint Energy holds a substantial limited partner interest in Enable (53.7% of the outstanding common units representing limited partner interests in Enable as of December 31, 2019), as well as 50% of the management rights in Enable GP and a 40% interest in the incentive distribution rights held by Enable GP. As of December 31, 2019, CenterPoint Energy owned an aggregate of 14,520,000 Enable Series A Preferred Units representing limited partner interests in Enable. Accordingly, CenterPoint Energy’s future earnings, results of operations, cash flows and financial condition will be affected by the performance of Enable, the amount of cash distributions it receives from Enable and the value of its interests in Enable. Factors that may have a material impact on Enable’s performance and cash distributions, and, hence, the value of CenterPoint Energy’s interests in Enable, include the risk factors outlined below, as well as the risks described elsewhere under “Risk Factors” that are applicable to Enable.

CenterPoint Energy’s cash flows will be adversely impacted if it receives less cash distributions from Enable than it currently expects or if it reduces its ownership in Enable.

Both CenterPoint Energy and OGE hold their limited partner interests in Enable in the form of common units. CenterPoint Energy also holds Enable Series A Preferred Units. For the Enable Series A Preferred Units, Enable is expected to pay $0.625 per Enable Series A Preferred Unit, or $2.50 per Enable Series A Preferred Unit on an annualized basis. However, 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. Enable is expected to pay a minimum quarterly distribution of $0.2875 per unit, or $1.15 per unit on an annualized basis, on its outstanding common units to the extent it has sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to Enable GP and its affiliates (referred to as “available cash”). Enable may not have sufficient available cash each quarter to enable it (i) to pay distributions on the Enable Series A Preferred Units or (ii) maintain or increase the distributions on its common 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;

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

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

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

• cash calls and settlements of hedging positions;

• margin requirements on open price risk management assets and liabilities;

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• the level of competition from other companies offering midstream services;

• adverse effects of governmental and environmental regulation;

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

• prevailing economic conditions.

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

• the level and timing of its capital expenditures;

• the cost of acquisitions;

• its debt service requirements and other liabilities;

• fluctuations in its working capital needs;

• its ability to borrow funds and access capital markets;

• restrictions contained in its debt agreements;

• the amount of cash reserves established by Enable GP;

• distributions paid on the Enable Series A Preferred Units;

• any impact on cash levels should any sale of CenterPoint Energy’s investment in Enable occur, as discussed further below; and

• other business risks affecting its cash levels.

Additionally, although it has no current plan to do so, CenterPoint Energy may also reduce its ownership in Enable over time through sales in the public equity markets, or otherwise, of the Enable common units it holds, subject to market conditions. CenterPoint Energy’s ability to execute any sale of Enable common units is subject to a number of uncertainties, including the timing, pricing and terms of any such sale. Any sales of Enable common units CenterPoint Energy owns could have an adverse impact on the price of Enable common units or on any trading market for Enable common units. Further, CenterPoint Energy’s sales of Enable common units may have an adverse impact on Enable’s ability to issue equity on satisfactory terms, or at all, which may limit its ability to expand operations or make future acquisitions. Any reduction in CenterPoint Energy’s interest in Enable would result in decreased distributions from Enable and decrease income, which may adversely impact CenterPoint Energy’s ability to meet its payment obligations and pay dividends on its Common Stock. Further, any sales of Enable common units would result in a significant amount of taxes due, which could also significantly impact CenterPoint Energy’s determination to execute any sale. There can be no assurances that any sale of Enable common units in the public equity markets or otherwise will be completed. Any sale of Enable common units in the public equity markets or otherwise may involve significant costs and expenses, including, in connection with any public offering, a significant underwriting discount. CenterPoint Energy may not realize any or all of the anticipated strategic, financial, operational or other benefits from any completed sale or reduction in its investment in Enable. Furthermore, under certain circumstances, including following certain changes in the methodology employed by rating agencies whereby the Enable Series A Preferred Units are no longer eligible for the same or a higher amount of “equity credit” attributed to the Enable Series A Preferred Units on their original issue date (referred to as a “rating event”), Enable has the option to redeem the Enable Series A Preferred Units. There can be no assurances that CenterPoint Energy will be able to reinvest any proceeds from such redemption in a manner that provides for a similar rate of return as the Enable Series A Preferred Units.

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

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

Enable is required to, or may at its option, redeem the Enable Series A Preferred Units in certain circumstances, and Enable may not have sufficient funds to redeem the Enable Series A Preferred Units if required to do so.

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

Additionally, Enable may redeem the Enable Series A Preferred Units under certain circumstances, including following a rating event. Upon a rating event, the Enable Series A Preferred Units may be considered by Enable to be an expensive form of indebtedness. If Enable does not have sufficient funds to exercise its option to redeem the Enable Series A Preferred Units upon a rating event, then such inability could have a material adverse effect on Enable’s business, financial position, results of operations and ability to make quarterly cash distributions to its unitholders.

CenterPoint Energy is not able to exercise control over Enable, which entails certain risks.

Enable is controlled jointly by CenterPoint Energy and OGE, who each own 50% of the management rights in Enable GP. The board of directors of Enable GP is composed of an equal number of directors appointed by OGE and by CenterPoint Energy, the president and chief executive officer of Enable GP and three directors who are independent as defined under the independence standards established by the NYSE. Accordingly, CenterPoint Energy is not able to exercise control over Enable.

Although CenterPoint Energy jointly controls Enable with OGE, CenterPoint Energy may have conflicts of interest with Enable that could subject it to claims that CenterPoint Energy has breached its fiduciary duty to Enable and its unitholders.

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

Enable is subject to various operational risks, all of which could affect Enable’s ability to make cash distributions to CenterPoint Energy.

The execution of Enable’s businesses is subject to a number of operational risks, which include, but are not limited to, the following:

• Contract Renewal: Enable’s contracts are subject to renewal risks. To the extent Enable is unable to renew or replace its expiring contracts on terms that are favorable, if at all, or successfully manage its overall contract mix over time, its financial position, results of operations and ability to make cash distributions could be adversely affected;

• Customers: Enable depends on a small number of customers for a significant portion of its gathering and processing revenues and its transportation and storage revenues. The loss of, or reduction in volumes from, these customers or the failure to extend or replace these contracts or the extension or replacement of these contracts on less favorable terms, as a result of competition or otherwise, could result in a decline in sales of its gathering and processing or transportation

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and storage services and adversely affect Enable’s financial position, results of operations and ability to make cash distributions;

• Third-Party Drilling and Production Decisions: Enable’s businesses are dependent, in part, on the natural gas and crude oil drilling and production market conditions and decisions of others, over which Enable has no control. Further, sustained reductions in exploration or production activity in Enable’s areas of operation and fluctuations in energy prices could lead to further reductions in the utilization of Enable’s systems, which could adversely affect its financial position, results of operations and ability to make cash distributions. It may also become more difficult to maintain or increase the current volumes on Enable’s gathering systems and in its processing plants, as several of the formations in the unconventional resource plays in which it operates generally have higher initial production rates and steeper production decline curves than wells in more conventional basins. Should Enable determine that the economics of its gathering assets do not justify the capital expenditures needed to grow or maintain volumes associated therewith, Enable may reduce such capital expenditures, which could cause revenues associated with these assets to decline over time;

• Competition: Enable competes with similar enterprises, some of which include public and private energy companies with greater financial resources and access to natural gas, NGL and crude oil supplies, in its respective areas of operation, primarily through rates, terms of service and flexibility and reliability of service. Increased competitive pressure in Enable’s industry, which is already highly competitive, could adversely affect Enable’s financial position, results of operations and ability to make cash distributions;

• Cost Recovery of Capital Improvements: Enable may not be able to recover the costs of its substantial planned investment in capital improvements and additions, and the actual cost of such improvements and additions may be significantly higher than it anticipates. In Enable’s Form 10-K for the fiscal year ended December 31, 2019, Enable stated that it expects that its expansion capital could range from approximately $160 million to $240 million and its maintenance capital could range from approximately $110 million to $130 million for the year ending December 31, 2020;

• Commodity Prices: Natural gas, NGL and crude oil prices are volatile, and changes in these prices could adversely affect Enable’s financial position, results of operations and ability to make cash distributions. Factors affecting prices are beyond Enable’s control and include the following: (i) demand for these commodities, which fluctuates with changes in market and economic conditions and other factors, including the impact of seasonality and weather, general economic conditions, the level of domestic and offshore natural gas production and consumption, (ii) the availability of imported natural gas, LNG, NGLs and crude oil, (iii) actions taken by foreign natural gas and oil producing nations, (iv) the availability of local, intrastate and interstate transportation systems, (v) the availability and marketing of competitive fuels, (vi) the impact of energy conservation efforts, technological advances affecting energy consumption and (vii) the extent of governmental regulation and taxation. Further, Enable’s natural gas processing arrangements expose it to commodity price fluctuations. In 2019, 4%, 26% and 70% of Enable’s processing plant inlet volumes consisted of keep-whole arrangements, percent-of-proceeds or percent-of-liquids and fee-based, respectively. If the price at which Enable sells natural gas or NGLs is less than the cost at which Enable purchases natural gas or NGLs under these arrangements, then Enable’s financial position, results of operations and ability to make cash distributions could be adversely affected;

• Credit Risk of Customers: Enable is exposed to credit risks of its customers, and any material nonpayment or nonperformance by its customers, whether through severe financial problems or otherwise, could adversely affect its financial position, results of operations and ability to make cash distributions;

• “Negotiated Rate” Contracts: Enable provides certain transportation and storage services under fixed-price “negotiated rate” contracts, which are authorized by the FERC, that are not subject to adjustment, even if its cost to perform these services exceeds the revenues received from these contracts. As of December 31, 2019, approximately 37% of Enable’s aggregate contracted firm transportation capacity on EGT and MRT and 93% of its aggregate contracted firm storage capacity on EGT and MRT, was subscribed under such “negotiated rate” contracts. The majority of Enable’s aggregate contracted firm transportation capacity and all of its aggregate contracted firm storage capacity under negotiated rate contracts on MRT are subject to the FERC’s rate case approval. As a result, Enable’s costs could exceed its revenues received under these contracts, and if Enable’s costs increase and it is not able to recover any shortfall of revenue associated with its negotiated rate contracts, the cash flow realized by its systems could decrease and, therefore, the cash Enable has available for distribution could also decrease;

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• Unavailability of Interconnected Facilities: If third-party pipelines and other facilities interconnected to Enable’s gathering, processing or transportation facilities (including those providing transportation of natural gas and crude oil, transportation and fractionation of NGLs and electricity for compression, among other things) become partially or fully unavailable for any reason, Enable’s financial position, results of operations and ability to make cash distributions could be adversely affected; and

• Land Ownership: Enable does not own all of the land on which its pipelines and facilities are located, and it is therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if it does not have valid rights-of-way or if such rights-of-way lapse or terminate, which could disrupt its operations or result in increased costs related to the construction and continuing operations elsewhere and adversely affect its financial position, results of operations and ability to make cash distributions.

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

Enable conducts a portion of its operations through joint ventures with third parties, including Enbridge Inc., DCP Midstream, LP, CVR Energy, Inc., Trans Louisiana Gas Pipeline, Inc. and Pablo Gathering LLC. Enable may also enter into other joint venture arrangements in the future. These third parties may have obligations that are important to the success of the joint venture, such as the obligation to pay their share of capital and other costs of the joint venture.

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

• Enable shares certain approval rights over major decisions and may not be able to control decisions, including control of cash distributions to Enable from the joint venture;

• Enable may incur liabilities as a result of an action taken by its joint venture partners, including leaving Enable liable for the other joint venture partners’ shares of joint venture liabilities if those partners do not pay their share of the joint venture’s obligations;

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

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

• Enable’s joint venture partners may take actions contrary to its instructions or requests or contrary to its policies or objectives; and

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

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

Under certain circumstances, Enbridge Inc. could have the right to purchase Enable’s ownership interest in SESH at fair market value.

Enable owns a 50% ownership interest in SESH. The remaining 50% ownership interest is held by Enbridge Inc. CenterPoint Energy owns 53.7% of Enable’s common units, 100% of the Enable Series A Preferred Units and a 40% economic interest in Enable GP. Pursuant to the terms of the limited liability company agreement of SESH, as amended, if, at any time, CenterPoint

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Energy has a right to receive less than 50% of Enable’s distributions through its interests in Enable and Enable GP, or do not have the ability to exercise certain control rights, Enbridge Inc. could have the right to purchase Enable’s interest in SESH at fair market value, subject to certain exceptions.

Enable’s ability to grow is dependent in part on its ability to access external financing sources on acceptable terms.

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

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

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

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

As of December 31, 2019, Enable had approximately $4.0 billion of long-term debt outstanding, excluding the premiums, discounts and unamortized debt expense on their senior notes, $155 million outstanding under its commercial paper program and $250 million outstanding under the Enable Oklahoma Intrastate Transmission, LLC 6.25% senior notes due 2020, excluding unamortized premium. Enable has a $1.75 billion revolving credit facility for working capital, capital expenditures and other partnership purposes, including acquisitions, with no borrowings outstanding, of which approximately $1.59 billion in borrowing capacity was available as of December 31, 2019. As of January 31, 2020, Enable had $119 million outstanding under its commercial paper program and $1.63 billion of available borrowing capacity under its revolving credit facility. Enable has the ability to incur additional debt, subject to limitations in its credit facilities. The levels of Enable’s debt could have important consequences, including the following:

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

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

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

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

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

Further, any reductions in Enable’s credit ratings could increase its financing costs and the cost of maintaining certain contractual relationships. Enable cannot assure that its credit ratings will remain in effect for any given period of time or that a

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rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances warrant. If any of Enable’s credit ratings are below investment grade, it may have higher future borrowing costs, and Enable or its subsidiaries may be required to post cash collateral or letters of credit under certain contractual agreements. If cash collateral requirements were to occur at a time when Enable was experiencing significant working capital requirements or otherwise lacked liquidity, its financial position, results of operations and ability to make cash distributions could be adversely affected.

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

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

• permit its subsidiaries to incur or guarantee additional debt;

• incur or permit to exist certain liens on assets;

• dispose of assets;

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

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

• change the nature of its business.

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

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

Enable’s businesses are exposed to various regulatory risks.

Enable’s operations are subject to extensive regulation by federal, state and local regulatory authorities. Changes or additional regulatory measures adopted by such authorities could adversely affect Enable’s financial position, results of operations and ability to make cash distributions. This regulation includes, but is not limited to, the following:

• Rate Regulation: The rates charged by several of Enable’s pipeline systems, including for interstate gas transportation service provided by its intrastate pipelines, are regulated by the FERC. Enable’s pipeline operations that are not regulated by the FERC may be subject to state and local regulation applicable to intrastate natural gas transportation services and crude oil gathering services. The FERC and state regulatory agencies also regulate other terms and conditions of the services Enable may offer. If one of these regulatory agencies, on its own initiative or due to challenges by third parties, were to lower its tariff rates or deny any rate increase or other material changes to the types, or terms and conditions, of service Enable might propose or offer, the profitability of Enable’s pipeline businesses could suffer.

• FERC Revised Policy Statement and NOPR: In a series of related issuances on March 15, 2018, the FERC issued a Revised Policy Statement stating that it will no longer permit pipelines organized as MLPs to recover an income tax allowance in their cost-of-service rates. On July 18, 2018, FERC issued a Final Rule adopting procedures that are generally the same as proposed in a March 15, 2018 NOPR implementing the Revised Policy Statement and the corporate income tax rate reduction with certain clarifications and modifications. For more information, please read “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. If FERC requires Enable to establish new tariff rates for either its natural gas or crude oil pipelines that reflect a lower federal corporate income tax rate, it is possible the rates would be reduced, which could adversely affect Enable’s financial position, results of operations and ability to make cash distributions to its unitholders. With regard to FERC-jurisdictional

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rates on Enable’s crude oil pipelines, the FERC plans to address the Revised Policy Statement and corporate tax rate reduction in its next five-year review of the oil pipeline rate index, which will occur in 2020 and become effective July 1, 2021. The potential rate impacts from the revision are currently uncertain.

• Permits, Licenses and Approvals: Enable may be unable to obtain or renew federal or state permits, licenses or approvals necessary for its operations, which could inhibit its ability to do business. All of these permits, licenses, approval limits and standards require a significant amount of monitoring, record keeping and reporting to demonstrate compliance with the underlying permit, license, approval limit or standard. Noncompliance or incomplete documentation of Enable’s compliance status may result in the imposition of fines, penalties and injunctive relief. Further, to obtain new permits or renew permits and other approvals in the future, Enable may be required to prepare and present data to governmental authorities pertaining to potential adverse impact of a proposed project. Compliance with these regulatory requirements may be expensive and may significantly lengthen the time required to prepare applications and to receive authorizations and consequently could disrupt Enable’s project construction schedules;

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

• Jurisdictional Characterization of Assets: Enable’s natural gas gathering and intrastate transportation systems are generally exempt from the jurisdiction of the FERC under the NGA, and its crude oil gathering system in the Anadarko Basin is generally exempt from the jurisdiction of the FERC under ICA. FERC regulation may indirectly impact these businesses and the markets for products derived from these businesses. Natural gas gathering and intrastate crude oil gathering may receive greater regulatory scrutiny at the state level; therefore, Enable’s operations could be adversely affected should they become subject to the application of state regulation of rates and services. A change in the jurisdictional characterization of some of Enable’s assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of its assets, which may cause its revenues to decline and operating expenses to increase.

Other Risk Factors Affecting Our Businesses and/or CenterPoint Energy’s Interests in Enable Midstream Partners, LP

The success of the Merger depends, in part, on CenterPoint Energy’s ability to realize anticipated benefits and conduct an effective integration process.

The success of the Merger will depend, in part, on CenterPoint Energy’s ability to realize the expected benefits in the anticipated timeframe, including operating efficiencies, growth opportunities, cost savings and customer retention, from integrating CenterPoint Energy’s and Vectren’s businesses, while at the same time continuing to provide consistent, high quality services. The integration process could be complex, costly and time consuming, including the diversion of significant management time and resources thereto, and may result in the following challenges, among other things:

• unanticipated delays, disruptions, issues or costs in integrating operations, financial and accounting, information technology, communications and other systems;

• inconsistencies in procedures, practices, policies, controls, and standards;

• differences in compensation arrangements, management perspectives and corporate culture; and

• loss of or difficulties retaining talented employees or valuable third-party relationships.

CenterPoint Energy must also successfully adapt 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 integration 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’s operating results 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 the trading prices of its securities.

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Even with the successful integration of the businesses, CenterPoint Energy may not achieve the expected results or economic benefits, including any expected revenue or synergy opportunities. Failure to fully realize the anticipated benefits could adversely affect CenterPoint Energy’s results of operations, financial condition and cash flows.

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

We and Enable are subject to cyber and physical security risks related to adversaries attacking information technology systems, network infrastructure, technology and facilities used to conduct almost all of our and Enable’s business, which includes, among other things, (i) managing operations and other business processes and (ii) protecting sensitive information maintained in the normal course of business. For example, the operation of our electric generation, transmission and distribution systems are dependent on not only physical interconnection of our facilities but also on communications among the various components of our systems and third-party systems. This reliance on information and communication between and among those components has increased since deployment of the intelligent grid, smart devices and operational technologies across our businesses. Further, certain of the various internal systems we use to conduct our businesses are highly integrated. Consequently, a cyber-attack or unauthorized access in any one of these systems could potentially impact the other systems.

Similarly, our and Enable’s business operations are interconnected with external networks and facilities. The distribution of natural gas to our customers requires communications with Enable’s pipeline facilities and third-party systems. The gathering, processing and transportation of natural gas from Enable’s gathering, processing and pipeline facilities and crude oil gathering pipeline systems also rely on communications among its facilities and with third-party systems that may be delivering natural gas or crude oil into or receiving natural gas or crude oil and other products from Enable’s facilities. Disruption of those communications, whether caused by physical disruption such as storms or other natural disasters, by failure of equipment or technology or by manmade events, such as cyber-attacks or acts of terrorism, may disrupt our or Enable’s ability to conduct operations and control assets.

Cyber-attacks, 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 or Enable to possible legal claims and liability. Further, third parties, including vendors, suppliers and contractors, who perform certain services for us or administer and maintain our sensitive information, could also be targets of cyber-attacks and unauthorized access. Neither we nor Enable are fully insured against all cyber-security risks, any of which could adversely affect our reputation and could have a material adverse effect on either our or Enable’s results of operations, financial condition and/or cash flows.

As domestic and global cyber threats are on-going and increasing in sophistication, magnitude and frequency, our and Enable’s critical energy infrastructure may be targets of state-sponsored attacks, terrorist activities or otherwise that could disrupt our respective business operations. 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 either our or Enable’s results of operations, financial condition and/or cash flows.

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

In connection with our businesses, we and our vendors, suppliers and contractors collect and retain personally identifiable information (e.g., 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 are subject to operational and financial risks and liabilities arising from environmental laws and regulations.

Our operations and the operations of Enable are subject to stringent and complex laws and regulations pertaining to the environment. As an owner or operator of natural gas pipelines, distribution systems and storage, steam electric generating facilities

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and electric transmission and distribution systems, and the facilities that support these systems, we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as:

• restricting the way we manage hazardous and non-hazardous wastes, including wastewater discharges and air emissions;

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

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

• limiting airborne emissions from electric generating facilities, including particulate matter, sulfur dioxide (SO₂), nitrogen oxides (NOx), carbon dioxide (CO₂) and mercury, and the disposal non-hazardous substances such as CCRs, among other things;

• restricting the use of fossil fuels through future climate legislation or regulation;

• imposing requirements on or restricting the operations of facilities under the terms of permits issued pursuant to such environmental laws and regulations; and

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

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

• construct or acquire new facilities and equipment;

• acquire permits for facility operations or purchase emissions allowances;

• modify or replace existing and proposed equipment; and

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

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

In April 2015, the EPA finalized its CCR Rule, which regulates ash as non­‑hazardous material under the RCRA. Under the CCR Rule, Indiana Electric is required to complete integrity assessments and groundwater monitoring studies. In January 2018, Indiana Electric completed its first annual groundwater monitoring and corrective action report. This report identified localized impacts to groundwater near Indiana Electric’s coal impoundments. Further analysis is ongoing. In October 2018, Indiana Electric completed the CCR Rule’s required evaluation of the placement of Indiana Electric’s coal ash ponds. 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 must cease disposal of new ash in the ponds and commence closure of the ponds by August 31, 2020. Indiana Electric plans to seek extensions available under the CCR Rule that would allow it to continue to use the ponds through December 31, 2023. The inability to obtain 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 imposition of fines and penalties. Further, a release of coal ash that presents an imminent and substantial endangerment to health of the environment could result in remediation costs, civil and/or criminal penalties, claims, litigation, increased regulation and compliance costs and reputational damage, all of which could adversely affect the financial condition of Indiana Electric.

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

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

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 believes 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.

Our operations and Enable’s operations are subject to all of the risks and hazards inherent in their respective businesses of gathering, processing, transportation and storage of natural gas and crude oil and the generation, transmission and distribution of electricity, including:

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

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

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

• ruptures, fires and explosions; and

• other safety hazards affecting our operations.

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

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

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

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

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

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

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

• labor disputes;

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

• information technology failure that affects our ability to access customer information or causes us to lose confidential or proprietary data that materially and adversely affects our reputation or exposes us to legal claims; and

• catastrophic events such as fires, earthquakes, explosions, leaks, floods, droughts, hurricanes, ice storms, terrorism, wildfires, pandemic health events or other similar occurrences, including any environmental impacts related thereto, which catastrophic events may require participation in mutual assistance efforts by us or other utilities to assist in power restoration efforts.

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

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

We and Enable depend on senior executive officers and other key personnel. Our and Enable’s success depends on our and Enable’s ability to attract, effectively transition and retain key personnel. On February 19, 2020, our president and chief executive officer resigned from CenterPoint Energy. As a result of this departure, our board of directors is currently conducting a search to fill the role of chief executive officer. The inability to recruit and retain or effectively transition key personnel or the unexpected loss of key personnel may adversely affect our and Enable’s operations. In addition, because of the reliance on our and Enable’s management team, our and Enable’s future success depends in part on our and Enable’s 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 and Enable’s strategies.

Failure to attract and retain an appropriately qualified workforce could adversely impact our and Enable’s results of operations.

Our and Enable’s 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 and Enable’s 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 and Enable’s businesses. If we and Enable are unable to successfully attract and retain an appropriately qualified workforce, our and Enable’s results of operations could be negatively affected.

Climate change legislation and regulatory initiatives could result in increased operating costs and reduced demand for our or Enable’s services, including certain local initiatives to prohibit new NGD service and increase electrification initiatives.

Regulatory agencies have adopted, and from time to time consider adopting, new legislation and/or modifying existing laws and regulations, to reduce GHGs, and there continues to be a wide-ranging policy and regulatory debate, both nationally and

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internationally, regarding the potential impact of GHGs and possible means for their regulation.  Efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues.

In August 2018, the EPA proposed a CPP replacement rule, the ACE Rule, which was finalized in July 2019 and requires states to implement a program of energy efficiency improvement targets for individual coal-fired electric generating units. States have three years to develop state plans to implement the ACE Rule, and we do not expect a state ACE plan to be finalized and approved by the EPA until 2024. We are currently unable to predict the effect of a state plan to implement the ACE Rule but do not anticipate that such a plan would have a material effect on our results of operations, financial condition or cash flows. Additionally, the ACE Rule is currently subject to legal challenges. At this time, we are unable to determine what effect, if any, the legal challenges will have on the ACE Rule.

Following a finding by the EPA that certain GHGs represent an endangerment to human health, the EPA adopted two sets of rules regulating GHG emissions under the Clean Air Act, one that requires a reduction in emissions of GHGs from motor vehicles and another that regulates emissions of GHGs from certain large stationary sources. The EPA has also expanded its existing GHG emissions reporting requirements. These permitting and reporting requirements could lead to further regulation of GHGs by the EPA. As a distributor and transporter of natural gas, or a consumer of natural gas in its pipeline and gathering businesses, NGD’s or Enable’s revenues, operating costs and capital requirements, as applicable, could be adversely affected as a result of any regulatory action that would require installation of new control technologies or a modification of its operations or would have the effect of reducing the consumption of natural gas. Additionally, Houston Electric’s and Indiana Electric’s transmission and distribution businesses’ revenues could be adversely affected to the extent any resulting regulatory action has the effect of reducing consumption of electricity by ultimate consumers within its service territory. Likewise, incentives to conserve energy or use energy sources other than natural gas could result in a decrease in demand for our services. For further discussion, see “— Risk Factors Affecting Natural Gas Distribution and Competitive Energy Services Businesses —NGD and CES must compete with alternate energy sources, which could result in less natural gas marketed and have an adverse impact on our results of operations, financial condition and cash flows.”

Moreover, 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 NGD 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 NGD operational footprint have adopted initiatives to prohibit the construction of new NGD 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.

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

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

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

Certain of NGD’s and Enable’s pipeline operations are subject to pipeline safety laws and regulations. The DOT’s PHMSA has adopted regulations requiring pipeline operators to develop integrity management programs, including more frequent inspections and other measures, for transportation pipelines located in “high consequence areas,” which are those areas where a

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leak or rupture could do the most harm. The regulations require pipeline operators, including NGD and Enable, to, among other things:

• perform ongoing assessments of pipeline integrity;

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

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

• improve data collection, integration, and analysis;

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

• repair and remediate pipelines as necessary; and

• implement preventive and mitigating action.

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

Changes to pipeline safety laws and regulations that result in more stringent or costly safety standards could have a significant adverse effect on NGD and Enable. Changes to pipeline safety regulations occur frequently. For example, PHMSA published a final rule in October 2019 that extends and expands the reach of certain PHMSA integrity management requirements (e.g., period assessments, leak detection and repairs) regardless of proximity to a high consequence area. The adoption of new regulations requiring more comprehensive or stringent safety standards could require us to install new or modified safety controls, pursue new capital projects, or conduct maintenance programs on an accelerated basis, all of which could require us and Enable to incur increased and potentially significant operational costs.

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

We have risks associated with aging infrastructure assets, including the failure of equipment or processes and potential breakdowns due to such aging. The age of certain of our assets may result in a need for replacement or higher level of maintenance costs because of our risk based federal and state compliant integrity management programs.  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 NGD’s 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.

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

Several of our businesses have entered into and have in place collective bargaining agreements with different labor unions. We have several separate bargaining units, each with a unique collective bargaining agreement described below: 

• The collective bargaining agreement with IBEW Local 66 related to employees of Houston Electric is scheduled to expire in May 2020, for which negotiations are anticipated to begin in March 2020;

• The collective bargaining agreements with USW Locals 13-227 and 13-1 related to NGD’s employees in Texas are scheduled to expire in June 2022 and July 2022, respectively;

• The collective bargaining agreements with Gas Workers Union Local 340, IBEW Local 949 and OPEIU Local 12 and Mankato related to NGD employees in Minnesota are scheduled to expire in April 2020, December 2020, May 2021 and March 2021, respectively, and negotiations with Gas Workers Union Local 340 are currently in progress and expected to be completed before the April 2020 expiration;

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• The collective bargaining agreements with IBEW Local 1393, USW Locals 12213 and 7441 related to employees of NGD in Indiana are scheduled to expire in December 2020;

• The collective bargaining agreements with the Teamsters, Chauffeurs, Warehousemen and Helpers Union Local 135 and Utility Workers Union Local 175 related to employees of Indiana Electric were recently renegotiated and are scheduled to expire in September 2021 and October 2021, respectively; and

• The collective bargaining agreement with IBEW Local 702 related to employees of Indiana Electric is scheduled to expire in June 2022.

Additionally, Infrastructure Services negotiates various trade agreements through contractor associations.  The two primary associations are the DCA and the PLCA.  These trade agreements are with a variety of construction unions including Laborer’s International Union of North America, International Union of Operating Engineers, United Association of Journeymen and Apprentices of the Plumbing and Pipe Fitting Industry, and Teamsters.  The trade agreements have varying expiration dates in 2020, 2021 and 2022. In addition, these subsidiaries have various project agreements and small local agreements.  These agreements expire upon completion of a specific project or on various dates throughout the year.

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.

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

We operate in businesses that require sophisticated data collection, processing systems, software and other technology. Some of the technologies supporting the industries we serve are changing rapidly and increasing in complexity. New technologies will emerge or grow that may be superior to, or may not be compatible with, some of our existing technologies, and may require us to make significant 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 or Enable’s potential business strategies and strategic initiatives, including merger and acquisition activities and the disposition of assets or businesses, may not be completed or perform as expected.

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

On February 3, 2020, CenterPoint Energy, through VUSI, entered into the Securities Purchase Agreement to sell the businesses within its Infrastructure Services reportable segment. The transaction is expected to close in the second quarter of 2020. For

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further information, see Notes 6 and 23 to the consolidated financial statements. We can make no assurances regarding the completion of this sale, which could be subject to delays or otherwise not consummated.

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. The transaction is expected to close in the second quarter of 2020. For further information, see Notes 6 and 23 to the consolidated financial statements. We can make no assurances regarding the completion of this sale, which could be subject to delays or otherwise not consummated. As discussed in Note 16(d) to the consolidated financial statements, the existing CERC Corp. guarantees supporting CES’s obligations under natural gas supply, transportation and storage contracts will not terminate upon closing of the transaction. While the buyer has an obligation to use its reasonable best efforts to cause CERC Corp. to be released from the guarantees as of and following closing, if the buyer is unable to do so, CERC Corp. would continue to have significant exposure under the guarantees. Following closing, if CES were to default on the payment obligations still guaranteed by CERC Corp., CERC Corp. could be obligated for such amounts.

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

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

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

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

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

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

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

The Registrants are subject to numerous legal proceedings, the most significant of which are summarized in Note 16 to the Registrants’ respective consolidated financial statements. Litigation is subject to many uncertainties, and the Registrants cannot predict the outcome of all matters with assurance. Final resolution of these matters may require additional expenditures over an extended period of time that may be in excess of established insurance or reserves and may have a material adverse effect on the Registrants’ financial results.

The Registrants could incur liabilities associated with businesses and assets that they have transferred to others.

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

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

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

In connection with the organization and capitalization of RRI (now GenOn) and Texas Genco (now an affiliate of NRG), those companies and/or their subsidiaries assumed liabilities associated with various assets and businesses transferred to them and agreed to certain indemnity agreements of the Registrants. Such indemnities have applied in various asbestos and other environmental matters that arise from time to time and cases such as the litigation arising out of sales of natural gas in California and other markets, including in the gas market manipulation cases described in Note 16(e) to the Registrants’ respective consolidated financial statements. However, because of the settlement and discharge of certain of GenOn’s indemnity obligations in 2019 in

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its Chapter 11 bankruptcy proceedings, the Registrants will no longer have the benefit of any settled or discharged indemnities and could incur liabilities in matters that previously would have been indemnified.

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

We are exposed to risks related to reduction in energy consumption due to factors such as unfavorable economic conditions in our service territories and changes in customers’ perceptions from recent incidents of other utilities involving natural gas pipelines.

Our businesses are affected by reduction in energy consumption due to factors including economic climate 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 recent 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, such as population changes, job and income growth, housing starts, new business formation and the overall level of economic activity.

Declines in demand for natural gas in NGD’s territories due to recent pipeline incidents of other utilities and for electricity as a result of economic downturns in Houston Electric’s and Indiana Electric’s regulated electric service territories will reduce overall sales and lessen cash flows, especially as industrial customers reduce production and, therefore, consumption of electricity. 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 sold as a result of economic downturn or recession could reduce revenues and cash flows, thereby diminishing results of operations. Additionally, prolonged economic downturns that negatively impact results of operations and cash flows could result in future material impairment charges to write-down the carrying value of certain assets, including goodwill, to their respective fair values.

For example, Houston Electric’s business is largely concentrated in Houston, Texas, where a higher percentage of employment is tied to the energy sector relative to other regions of the country. Although Houston, Texas has a diverse economy, employment in the energy industry remains important with overall Houston employment growing at a moderate rate in 2019 among various sectors. Further, the operations of Vectren’s utility businesses are concentrated in central and southern Indiana and west-central Ohio and are therefore impacted by changes in the Midwest economy in general and changes in particular industries concentrated in the Midwest.  These industries include automotive assembly, parts and accessories; feed, flour and grain processing; metal castings, plastic products; gypsum products; electrical equipment, metal specialties, glass and steel finishing; pharmaceutical and nutritional products; gasoline and oil products; ethanol; and coal mining.

In the event economic conditions further decline, the respective rates of growth in Houston, Indiana and the other areas in which we operate may also deteriorate. Changing market conditions, including changing regulation, changes in market prices of oil or other commodities, or changes in government regulation and assistance, may cause certain industrial customers to reduce or cease production and thereby decrease consumption of natural gas and/or electricity. Increases in customer defaults or delays in payment due to liquidity constraints could negatively impact our cash flows and financial condition. 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.

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

We are committed to living our core values of safety, integrity, accountability, initiative and respect and complying with all applicable laws and regulations. Despite that commitment and our efforts to prevent misconduct, it is possible for employees to engage in intentional misconduct, fail to uphold our core values, and violate laws and regulations for individual gain through contract or procurement fraud, misappropriation, bribery or corruption, fraudulent related-party transactions and serious breaches of 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

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negative public perceptions, any of which could have a material adverse effect on our results of operations, financial condition and cash flows.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

The following discussion is based on the Registrants’ businesses and equity method investment as of December 31, 2019.

Character of Ownership

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

Houston Electric T&D (CenterPoint Energy and Houston Electric)

For information regarding the properties of the Houston Electric T & D reportable segment, please read “Business — Our Business — Houston Electric Transmission & Distribution — Properties” in Item 1 of this report, which information is incorporated herein by reference.

Indiana Electric Integrated (CenterPoint Energy)

For information regarding the properties of the Indiana Electric Integrated reportable segment, please read “Business — Our Business — Indiana Electric Integrated — Properties” in Item 1 of this report, which information is incorporated herein by reference.

Natural Gas Distribution (CenterPoint Energy and CERC)

For information regarding the properties of the Natural Gas Distribution reportable segment, please read “Business — Our Business — Natural Gas Distribution — Assets” in Item 1 of this report, which information is incorporated herein by reference.

Energy Services (CenterPoint Energy and CERC)

For information regarding the properties of the Energy Services reportable segment, please read “Business — Our Business — Energy Services — Assets” in Item 1 of this report, which information is incorporated herein by reference.

Infrastructure Services (CenterPoint Energy)

For information regarding the properties of the Infrastructure Services reportable segment, please read “Business — Our Business — Infrastructure Services” in Item 1 of this report, which information is incorporated herein by reference.

Midstream Investments (CenterPoint Energy)

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

Corporate and Other (CenterPoint Energy and CERC)

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

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Item 3. Legal Proceedings

For a discussion of material legal and regulatory proceedings affecting the Registrants as of December 31, 2019, 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.

Item 4. Mine Safety Disclosures

Not applicable.

PART II

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

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

CenterPoint Energy

As of February 19, 2020, CenterPoint Energy’s common stock was held by approximately 27,524 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.

Repurchases of Equity Securities

During the quarter ended December 31, 2019, none of CenterPoint Energy’s equity securities registered pursuant to Section 12 of the Securities Exchange Act of 1934 were purchased by or on behalf of CenterPoint Energy or any “affiliated purchasers,” as defined in Rule 10b-18(a)(3) under the Securities Exchange Act of 1934.

Houston Electric

As of February 19, 2020, all of Houston Electric’s 1,000 outstanding common shares were held by Utility Holding, LLC, a wholly-owned subsidiary of CenterPoint Energy.

CERC

As of February 19, 2020, all of CERC Corp.’s 1,000 outstanding shares of common stock were held by Utility Holding, LLC, a wholly-owned subsidiary of CenterPoint Energy.

Item 6.        Selected Financial Data (CenterPoint Energy)

The following table presents selected financial data with respect to CenterPoint Energy’s consolidated financial condition and consolidated results of operations and should be read in conjunction with CenterPoint Energy’s consolidated financial statements and the related notes in Item 8 of this report.

	Year Ended December 31,
	2019		2018		2017			2016		2015
	(in millions, except per share amounts)
Revenues	$	12,301	$	10,589	$	9,614		$	7,528	$	7,386
Equity in earnings (losses) of unconsolidated affiliates, net	230		307		265			208		(1,663		)	(2)
Income (loss) available to common shareholders	674		333		1,792		(1)	432		(692		)
Basic earnings (loss) per common share	1.34		0.74		4.16			1.00		(1.61		)
Diluted earnings (loss) per common share	1.33		0.74		4.13			1.00		(1.61		)

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	Year Ended December 31,
	2019			2018			2017			2016			2015
	(in millions, except per share amounts)
Cash dividends paid per common share	$	1.15		$	1.11		$	1.07		$	1.03		$	0.99
Dividend payout ratio	86		%	150		%	26		%	103		%	n/a
Return on average common equity	8		%	5		%	44		%	12		%	(17		)%
At year-end:
Book value per common share	$	16.64		$	16.08		$	10.88		$	8.04		$	8.05
Market price per common share	27.27			28.23			28.36			24.64			18.36
Market price as a percent of book value	164		%	176		%	261		%	306		%	228		%
Percentage of common units owned representing limited partner interests in Enable	53.7		%	54.0		%	54.1		%	54.1		%	55.4		%
Total assets (3) (4)	$	35,439		$	27,009		$	22,736		$	21,829		$	21,290
Short-term borrowings	—			—			39			35			40
Securitization Bonds, including current maturities	977			1,435			1,868			2,278			2,667
Other long-term debt, including current maturities (5)	14,135			7,729			6,933			6,279			6,063
Capitalization:
Common stock equity	36		%	47		%	35		%	29		%	28		%
Long-term debt, including current maturities	64		%	53		%	65		%	71		%	72		%
Capitalization, excluding Securitization Bonds:
Common stock equity	37		%	51		%	40		%	36		%	36		%
Long-term debt, excluding Securitization Bonds, and including current maturities	63		%	49		%	60		%	64		%	64		%
Capital expenditures	$	2,587		$	1,720		$	1,494		$	1,406		$	1,575

(1) Income (loss) available to common shareholders for the year ended December 31, 2017 includes a reduction in income tax expense of $1,113 million due to tax reform. See Note 15 to the consolidated financial statements for further discussion of the impacts of the TCJA implementation.

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

(3) The increase in Total assets as of December 31, 2019, as compared to December 31, 2018, was primarily driven by the assets acquired in the Merger.

(4) Total assets as of December 31, 2018 include cash and cash equivalents of $4.2 billion.

(5) The increase in Other long-term debt, including current maturities as of December 31, 2019, as compared to December 31, 2018, was primarily driven by debt incurred to finance the Merger and debt acquired in the Merger.

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

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

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

OVERVIEW

Background

CenterPoint Energy, Inc. is a public utility holding company and owns interests in Enable. CenterPoint Energy’s operating subsidiaries own and operate electric transmission and distribution, electric generation and natural gas distribution facilities, supply natural gas to commercial and industrial customers and electric and natural gas utilities and provide underground pipeline

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construction and repair services, energy performance contracting and sustainable infrastructure services. For a detailed description of CenterPoint Energy’s operating subsidiaries, please read Note 1 to the consolidated financial statements.

Houston Electric is an indirect, wholly-owned subsidiary of CenterPoint Energy that provides electric transmission and distribution services 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 with operating subsidiaries that own and operate natural gas distribution facilities in six states and supply natural gas to commercial and industrial customers and electric and natural gas utilities in over 30 states.

Reportable Segments

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

As of December 31, 2019, reportable segments by Registrant are as follows:

Registrants	Houston Electric T&D	Indiana Electric Integrated	Natural Gas Distribution	Energy  Services	Infrastructure Services	Midstream Investments	Corporate and Other
CenterPoint Energy	X	X	X	X	X	X	X
Houston Electric	X
CERC			X	X			X

• Houston Electric T&D reportable segment includes electric transmission and distribution services that are subject to rate regulation and impacts of generation-related stranded costs and other true-up balances recoverable by the regulated electric utility. For further information about the Houston Electric T&D reportable segment, see “Business — Our Business — Houston Electric T&D” in Item 1 of Part I of this report.

• Indiana Electric Integrated reportable segment includes energy delivery services to electric customers and electric generation assets to serve its electric customers and optimize those assets in the wholesale power market. For further information about the Indiana Electric Integrated reportable segment, see “Business — Our Business — Indiana Electric Integrated” in Item 1 of Part I of this report.

• Natural Gas Distribution reportable segment includes natural gas distribution services that are subject to rate regulation in CenterPoint Energy’s and CERC’s service territories, as well as home appliance maintenance and repair services to customers in Minnesota. For further information about the Natural Gas Distribution reportable segment, see “Business — Our Business — Natural Gas Distribution” in Item 1 of Part I of this report.

• Energy Services reportable segment includes non-rate regulated natural gas sales to, and transportation and storage services, for commercial and industrial customers. For further information about the Energy Services reportable segment, see “Business — Our Business — Energy Services” in Item 1 of Part I of this report.

• Infrastructure Services reportable segment includes underground pipeline construction and repair services. For further information about the Infrastructure Services reportable segment, see “Business — Our Business — Infrastructure Services” in Item 1 of Part I of this report.

• Midstream Investments reportable segment includes CenterPoint Energy’s equity investment in Enable and is dependent upon the results of Enable, which are driven primarily by the volume of natural gas, NGLs and crude oil that Enable gathers, processes and transports across its systems and other factors as discussed below under “— Factors Influencing Midstream Investments.” For further information about the Midstream Investments reportable segment, see “Business — Our Business — Midstream Investments” in Item 1 of Part I of this report.

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• CenterPoint Energy’s Corporate and Other reportable segment includes office buildings and other real estate used for business operations, home repair protection plans to natural gas customers in Texas and Louisiana through a third party, energy performance contracting and sustainable infrastructure services and other corporate support operations CERC’s Corporate and Other reportable segment includes unallocated corporate costs and inter-segment eliminations.

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 is expected to close in the second quarter of 2020. For further information, see Notes 6 and 23 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. The transaction is expected to close in the second quarter of 2020. For further information, see Notes 6 and 23 to the consolidated financial statements.

EXECUTIVE SUMMARY

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

Factors Influencing Our Businesses and Industry Trends

We are an energy delivery company. 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 include Infrastructure Services and ESG. Infrastructure Services, through its wholly-owned subsidiaries, provides underground pipeline and repair services to many utilities, including our utilities, as well as other industries. 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. Concurrent with the completion of the Merger, 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 businesses within its Infrastructure Services reportable segment. The transaction is expected to close in the second quarter of 2020. For further information, see Notes 6 and 23 to the consolidated financial statements.

To assess our financial performance, our management primarily monitors operating 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, commodity prices and heating and cooling degree days. From an operational standpoint, we monitor operation and maintenance expense, safety factors, system reliability and customer satisfaction to gauge our performance.

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. 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, Houston Electric is largely concentrated in Houston, Texas, where a higher percentage of employment is tied to the energy sector relative to other regions of the country. Despite Houston, Texas having a diverse economy, employment

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in the energy industry remains important with overall Houston employment growing at a moderate rate in 2019 among various sectors. Although the Houston area represents a large part of our customer base, we have a diverse customer base throughout the eight states we serve.  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.  In Minnesota, for instance, education and health services are the state’s largest sectors, whereas Arkansas has a large food manufacturing industry. 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. Further, the operations of Vectren’s utility businesses are concentrated in central and southern Indiana and west-central Ohio and are therefore impacted by changes in the Midwest economy in general and changes in particular industries concentrated in the Midwest.  These industries include automotive assembly, parts and accessories; feed, flour and grain processing; metal castings; plastic products; gypsum products; electrical equipment; metal specialties; glass and steel finishing; pharmaceutical and nutritional products; gasoline and oil products; ethanol; and coal mining.

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. Multifamily residential customer growth is affected by the cyclical nature of apartment construction. Beginning in 2019, a new construction cycle in Houston helped overall residential customer growth to return to 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 Distribution reportable segment is approximately 1%. CERC’s NGD customer growth was 1.3% for 2019, which is slightly higher than in previous years.

Performance of the Houston Electric T&D reportable segment and the Natural Gas Distribution 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 CERC’s NGD, 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 2019, the Houston area experienced weather that was closer to normal compared to 2018. Although the summer months, particularly August and September, were hotter than normal, this was offset during the remaining months of the year due to milder than normal weather. While overall rainfall was higher than normal in 2019 largely due to Tropical Storm Imelda, it did not rise to the record rainfall levels experienced in 2017 that occurred largely due to Hurricane Harvey. After a return to more normal weather in 2018, our NGD service territories experienced warmer weather in 2019 in all areas except Minnesota.

Historically, both CenterPoint Energy’s TDU and CERC’s NGD have utilized weather hedges to help reduce the impact of mild weather on their financial results. CenterPoint Energy’s TDU and CERC’s NGD entered into a weather hedge for the 2018–2019 and 2019–2020 winter heating seasons in Texas where no weather normalization mechanisms exist. In CERC’s non-Texas jurisdictions, weather normalization mechanisms or decoupling in the Minnesota division help to mitigate the impact of abnormal weather on our financial results. 

In Minnesota and Arkansas for CERC’s NGD, there are rate adjustment mechanisms to counter the impact of declining usage from energy efficiency improvements. In addition, in many of our service areas, particularly in the Houston area and Minnesota, as applicable to each registrant, we have benefited from growth in the number of customers, which could mitigate the effects of reduced consumption. We anticipate that this trend will continue as the regions’ economies continue to grow. The profitability of our businesses is influenced significantly by the regulatory treatment we receive from the various state and local regulators who set our electric and natural gas distribution rates.

Sales of natural gas and electricity 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. 

In our NGD 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 NGD 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

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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.

On April 5, 2019, and subsequently adjusted in errata filings in May and June 2019, Houston Electric filed its base rate application with the PUCT and the cities in its service area to change its rates. A settlement has been reached and a final order from the PUCT is expected during the first quarter of 2020. For details related to our pending and completed regulatory proceedings and orders related to the TCJA in 2019 and to date in 2020, 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 T&D reportable segment and Natural Gas Distribution reportable segment in their Texas jurisdictions. CenterPoint Energy expects to contribute a minimum of approximately $83 million to its pension plans in 2020.

Factors Influencing Our Businesses Proposed for Divestiture

The Energy Services reportable segment contracts with customers for transportation, storage and sales of natural gas on an unregulated basis. Its operations serve customers throughout the United States. The segment is impacted by price differentials on both a regional and seasonal basis, as well as fluctuations in regional daily natural gas prices driven by weather and other market factors. While this business utilizes financial derivatives to mitigate the effects of price movements, it does not enter into risk management contracts for speculative purposes and evaluates VaR daily to monitor significant financial exposures to realized income. Energy Services experienced instances of decreased margin in 2019 due to fewer opportunities to optimize natural gas supply costs as compared to 2018. Specifically, weather-facilitated market impacts in various regions of the continental United States during the three months ended March 31, 2018 allowed Energy Services to increase its margins in the first quarter of 2018. 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. The transaction is expected to close in the second quarter of 2020. For further information, see Notes 6 and 23 to the consolidated financial statements.

Demand for Infrastructure Services remains high due to the aging infrastructure and evolving safety and reliability regulations across the United States. The long-term focus for Infrastructure Services is recurring work in both the distribution and transmission businesses. The timing and recurrence of large transmission projects is less predictable and may create volatility in its year-over-year results. 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 is expected to close in the second quarter of 2020. For further information, see Notes 6 and 23 to the consolidated financial statements.

Factors Influencing Midstream Investments (CenterPoint Energy)

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.

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Enable’s business is impacted by commodity prices, which have declined and otherwise experienced significant volatility in recent years. Commodity prices impact the drilling and production of natural gas and crude oil in the areas served by Enable’s systems. In addition, Enable’s processing arrangements expose it to commodity price fluctuations. Enable has attempted to mitigate the impact of commodity prices on its business by entering into hedges, focusing on contracting fee-based business and converting existing commodity-based contracts to fee-based contracts.

Enable’s long-term view is that natural gas and crude oil production in the U.S. will increase. Advancements in technology have allowed producers to efficiently extract natural gas and crude oil from tight gas formations and shale plays. As a result, the proven reserves of natural gas and crude oil in the United States have significantly increased. As proven reserves of natural gas and crude oil have continued to increase, the supply growth has outpaced demand growth, resulting in oversupply. The oversupply of natural gas and crude oil has resulted in price declines over the last year. Natural gas continues to be a critical component of energy demand in the U.S. Enable’s management believes that, although oversupply will continue in the near term, the prospects for continued natural gas demand are favorable over the long term and will be driven by population and economic growth, the continued displacement of coal-fired power plants by natural gas-fired power plants due to the price of natural gas and stricter government environmental regulations on the mining and burning of coal and the continued development of a global export market for LNG. Enable’s management believes that increasing consumption of natural gas over the long term, both within the United States and in the global export market for LNG, will continue to drive demand for Enable’s natural gas gathering, processing, transportation and storage services.

Significant Events

Proposed Divestiture of 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 is expected to close in the second quarter of 2020. For further information, see Notes 6 and 23 to the consolidated financial statements.

Proposed Divestiture of CES. 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. The transaction is expected to close in the second quarter of 2020. For further information, see Notes 6 and 23 to the consolidated financial statements.

Regulatory Proceedings. On April 5, 2019, and subsequently adjusted in errata filings in May and June 2019, Houston Electric filed its base rate application with the PUCT and the cities in its service area to change its rates. A settlement has been reached and a final order from the PUCT in the proceeding is expected during the first quarter of 2020. For details related to our pending and completed regulatory proceedings and orders related to the TCJA in 2019 and to date in 2020, see “—Liquidity and Capital Resources —Regulatory Matters” in Item 7 of Part II of this report, which discussion is incorporated herein by reference.

Merger with Vectren. On February 1, 2019, pursuant to the Merger Agreement, CenterPoint Energy consummated the previously announced Merger and acquired Vectren for approximately $6 billion in cash. For more information about the Merger, see Notes 1 and 4 to the consolidated financial statements.

Debt Transactions. In January 2019, Houston Electric issued $700 million aggregate principal amount of general mortgage bonds, in May 2019, CenterPoint Energy entered into a $1.0 billion variable rate term loan and in August 2019, CenterPoint Energy issued $1.2 billion aggregate principal amount of senior notes. For more information about the 2019 debt transactions, see Note 14 to the consolidated financial statements.

CERTAIN FACTORS AFFECTING FUTURE EARNINGS

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

• the performance of Enable, the amount of cash distributions CenterPoint Energy receives from Enable, Enable’s ability to redeem the Enable Series A Preferred Units in certain circumstances and the value of CenterPoint Energy’s interest in Enable, and factors that may have a material impact on such performance, cash distributions and value, including factors such as:

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

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

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

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

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

◦ the timing of payments from Enable’s customers under existing contracts, including minimum volume commitment payments;

◦ changes in tax status; and

◦ access to debt and equity capital;

• the expected benefits of the Merger and integration, including the outcome of shareholder litigation filed against Vectren that could reduce anticipated benefits of the Merger, as well as the ability to successfully integrate the Vectren businesses and to realize anticipated benefits and commercial opportunities;

• the recording of impairment charges, including any impairment associated with Infrastructure Services and CES;

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

• the outcome of the pending Houston Electric rate case;

• timely and appropriate rate actions that allow recovery of costs and a reasonable return on investment;

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

• weather variations and other natural phenomena, including the impact of severe weather events on operations and capital;

• state and federal legislative and regulatory actions or developments affecting various aspects of our businesses (including the businesses of Enable), including, among others, energy deregulation or re-regulation, pipeline integrity and safety and changes in regulation and legislation pertaining to trade, health care, finance and actions regarding the rates charged by our regulated businesses;

• tax legislation, including the effects of the TCJA (which includes any potential changes to interest deductibility) and uncertainties involving state commissions’ and local municipalities’ regulatory requirements and determinations regarding the treatment of EDIT and our rates;

• CenterPoint Energy’s and CERC’s ability to mitigate weather impacts through normalization or rate mechanisms, and the effectiveness of such mechanisms;

• the timing and extent of changes in commodity prices, particularly natural gas and coal, and the effects of geographic and seasonal commodity price differentials on CERC and Enable;

• the ability of CenterPoint Energy’s and CERC’s non-utility business operating in the Energy Services reportable segment to effectively optimize opportunities related to natural gas price volatility and storage activities, including weather-related impacts;

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

• changes in interest rates and their impact on costs of borrowing and the valuation of CenterPoint Energy’s pension benefit obligation;

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

• the availability and prices of raw materials and services and changes in labor for current and future construction projects;

• local, state and federal legislative and regulatory actions or developments relating to the environment, including, among other things, those related to global climate change, air emissions, carbon, waste water discharges and the handling and

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disposal of CCR that could impact the continued operation, and/or cost recovery of generation plant costs and related assets;

• the impact of unplanned facility outages or other closures;

• any direct or indirect effects on our or Enable’s facilities, operations and financial condition resulting from terrorism, cyber-attacks, data security breaches or other attempts to disrupt our businesses or the businesses of third parties, or other catastrophic events such as fires, ice, earthquakes, explosions, leaks, floods, droughts, hurricanes, tornadoes, pandemic health events or other occurrences;

• our ability to invest planned capital and the timely recovery of our existing and future investments, including those related to Indiana Electric’s anticipated IRP;

• our ability to successfully construct and operate electric generating facilities, including complying with applicable environmental standards and the implementation of a well-balanced energy and resource mix, as appropriate;

• our ability to control operation and maintenance costs;

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

• the investment performance of CenterPoint Energy’s pension and postretirement benefit plans;

• commercial bank and financial market conditions, our access to capital, the cost of such capital, and the results of our financing and refinancing efforts, including availability of funds in the debt capital markets;

• changes in rates of inflation;

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

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

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

• timely and appropriate regulatory actions, which include actions allowing securitization, for any future hurricanes or natural disasters or other recovery of costs, including costs associated with Hurricane Harvey;

• CenterPoint Energy’s or Enable’s potential business strategies and strategic initiatives, including restructurings, joint ventures and acquisitions or dispositions of assets or businesses, including the proposed sales of Infrastructure Services and CES, which CenterPoint Energy and Enable cannot assure will be completed or will have the anticipated benefits to CenterPoint Energy or Enable;

• the performance of projects undertaken by our non-utility businesses and the success of efforts to realize value from, invest in and develop new opportunities and other factors affecting those non-utility businesses, including, but not limited to, the level of success in bidding contracts, fluctuations in volume and mix of contracted work, mix of projects received under blanket contracts, failure to properly estimate cost to construct projects or unanticipated cost increases in completion of the contracted work, changes in energy prices that affect demand for construction services and projects and cancellation and/or reductions in the scope of projects by customers and obligations related to warranties and guarantees;

• acquisition and merger activities involving us or our competitors, including the ability to successfully complete merger, acquisition and divestiture plans;

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

• the outcome of litigation;

• the ability of REPs, including REP affiliates of NRG and Vistra Energy Corp., formerly known as TCEH Corp., to satisfy their obligations to CenterPoint Energy and Houston Electric;

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

• the impact of alternate energy sources on the demand for natural gas;

• the timing and outcome of any audits, disputes and other proceedings related to taxes;

• the effective tax rates;

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

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

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

CENTERPOINT ENERGY CONSOLIDATED RESULTS OF OPERATIONS

	Year Ended December 31,
	2019			2018			2017
	(in millions, except per share amounts)
Revenues	$	12,301		$	10,589		$	9,614
Expenses	11,075			9,758			8,478
Operating Income	1,226			831			1,136
Gain (Loss) on Marketable Securities	282			(22		)	7
Gain (Loss) on Indexed Debt Securities	(292		)	(232		)	49
Interest and Other Finance Charges	(528		)	(361		)	(313		)
Interest on Securitization Bonds	(39		)	(59		)	(77		)
Equity in Earnings of Unconsolidated Affiliates, net	230			307			265
Other Income (Expense), net	50			50			(4		)
Income Before Income Taxes	929			514			1,063
Income Tax Expense (Benefit)	138			146			(729		)
Net Income	791			368			1,792
Preferred Stock Dividend Requirement	117			35			—
Income Available to Common Shareholders	$	674		$	333		$	1,792
Basic Earnings Per Common Share	$	1.34		$	0.74		$	4.16
Diluted Earnings Per Common Share	$	1.33		$	0.74		$	4.13

2019 Compared to 2018

Net Income.  CenterPoint Energy reported income available to common shareholders of $674 million ($1.33 per diluted common share) for 2019 compared to $333 million ($0.74 per diluted common share) for 2018.

The increase in income available to common shareholders of $341 million was primarily due to the following key factors:

• a $395 million increase in operating income, discussed below by reportable segment in Results of Operations by Reportable Segment;

• a $304 million increase in gain on marketable securities, included in Other Income (Expense), net shown above;

• a $20 million decrease in interest expense related to lower outstanding balances of the Securitization Bonds; and

• an $8 million decrease in income tax expense primarily due to the lower effective tax rate, as explained below, partially offset by higher income before income taxes.

These increases were partially offset by:

• a $167 million increase in interest expense, primarily as a result of higher outstanding long-term debt used to finance the Merger and additional long-term debt acquired in the Merger, discussed further in Notes 4 and 14 to the consolidated financial statements;

• an $82 million increase in preferred stock dividend requirements primarily as a result of the Merger;

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• a $77 million decrease to equity in earnings from the investment in Enable, which includes CenterPoint Energy’s share ($46 million) of Enable’s goodwill impairment charge recorded in the fourth quarter of 2019 discussed further in Note 11 to the consolidated financial statements; and

• a $60 million increase in losses on the underlying value of the indexed debt securities related to the ZENS included in Other Income (Expense), net shown above.

Income Tax Expense. CenterPoint Energy reported an effective tax rate of 15% and 28% for the years ended December 31, 2019 and 2018, respectively. The lower effective tax rate of 15% is due to an increase in the amount of amortization of the net regulatory EDIT liability as decreed by regulators in certain jurisdictions, the effect of state law changes that resulted in the remeasurement of state deferred taxes, and the impact of the reduction in valuation allowances on certain state net operating losses that are now expected to be realized.

2018 Compared to 2017

Net Income.  CenterPoint Energy reported income available to common shareholders of $333 million ($0.74 per diluted common share) for 2018 compared to $1,792 million ($4.13 per diluted common share) for 2017.

The decrease in income available to common shareholders of $1,459 million was primarily due to the following key factors:

• an $875 million increase in income tax expense, resulting from a reduction in income tax expense of $1,113 million due to tax reform in 2017, discussed further in Note 15 to the consolidated financial statements, offset by a $238 million decrease in income tax expense primarily due to a reduction in the corporate income tax rate resulting from the TCJA in 2018 and lower income before income taxes year over year;

• a $305 million decrease in operating income, discussed below by reportable segment in Results of Operations by Reportable Segment;

• a $281 million increase in losses on indexed debt securities related to the ZENS, resulting from a loss of $11 million from Meredith’s acquisition of Time in March 2018, a loss of $242 million from AT&T’s acquisition of TW in June 2018 and reduced gains of $28 million in the underlying value of the indexed debt securities;

• a $48 million increase in interest expense primarily due to higher outstanding other long-term debt and the amortization of Bridge Facility fees of $24 million;

• a $35 million increase in preferred stock dividend requirements; and

• a $29 million increase in losses on marketable securities.

These decreases were partially offset by:

• a $42 million increase in equity earnings from the investment in Enable, discussed further in Note 11 to the consolidated financial statements;

•a $25 million increase in interest income on investments included in Other Income (Expense), net shown above;

• a $17 million decrease in the non-service cost components of net periodic pension and post-retirement costs included in Other Income (Expense), net shown above;

•an $18 million decrease in interest expense related to lower outstanding balances of the Securitization Bonds;

•a $6 million increase in miscellaneous other non-operating income included in Other Income (Expense), net shown above;

• a $4 million increase in dividend income on CenterPoint Energy’s ZENS-Related Securities included in Other Income (Expense), net shown above; and

•a $2 million increase in gains on interest rate economic hedges included in Other Income (Expense), net shown above.

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Income Tax Expense. CenterPoint Energy reported an effective tax rate of 28% and (69)% for the years ended December 31, 2018 and 2017, respectively. The effective tax rate of 28% is primarily due to the reduction in the federal corporate income tax rate from 35% to 21% effective January 1, 2018 as prescribed by the TCJA and the amortization of EDIT. These decreases were partially offset by an increase to the effective tax rate as a result of the establishment of a valuation allowance on certain state net operating loss deferred tax assets that are no longer expected to be utilized prior to expiration after the Internal Spin. The effective tax rate was also increased for state law changes that resulted in remeasurement of state deferred taxes in those jurisdictions.

HOUSTON ELECTRIC CONSOLIDATED RESULTS OF OPERATIONS

Houston Electric’s results of operations are affected by seasonal fluctuations in the demand for electricity. Houston Electric’s results of operations are also affected by, among other things, the actions of various governmental authorities having jurisdiction over rates Houston Electric charges, debt service costs, income tax expense, Houston Electric’s ability to collect receivables from REPs and Houston Electric’s ability to recover its regulatory assets.

	Year Ended December 31,
	2019			2018			2017
	(in millions)
Revenues	$	2,990		$	3,234		$	2,998
Expenses	2,372			2,609			2,361
Operating Income	618			625			637
Interest and other finance charges	(164		)	(138		)	(128		)
Interest on Securitization Bonds	(39		)	(59		)	(77		)
Other income (expense), net	21			(3		)	(8		)
Income before income taxes	436			425			424
Income tax expense (benefit)	80			89			(9		)
Net income	$	356		$	336		$	433

2019 Compared to 2018

Net Income.  Houston Electric reported net income of $356 million for 2019 compared to $336 million for 2018.

The increase of $20 million in net income was primarily due to the following key factors:

• a $24 million increase in Other income (expense), net primarily due to increased interest income of $22 million mainly from investments in the CenterPoint Energy money pool;

• a $14 million increase in TDU operating income discussed below in Results of Operations by Reportable Segment, exclusive of an $8 million gain from weather hedges recorded at CenterPoint Energy; and

• a $9 million decrease in income tax expense primarily due to the lower effective tax rate, as explained below, partially offset by higher income before income taxes.

These increases to net income were partially offset by a $26 million increase in interest expense due to higher outstanding other long-term debt.

Income Tax Expense.  Houston Electric reported an effective tax rate of 18% and 21% for the years ended December 31, 2019 and 2018, respectively. The lower effective tax rate of 18% is due to an increase in the amount of amortization of the net regulatory EDIT liability as decreed by regulators.

2018 Compared to 2017

Net Income.  Houston Electric reported net income of $336 million for 2018 compared to net income of $433 million for 2017.

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The decrease of $97 million in net income was primarily due to the following key factors:

• a $98 million increase in income tax expense, resulting from a reduction in income tax expense of $158 million due to tax reform in 2017, discussed further in Note 15 to the consolidated financial statements, offset by a $60 million decrease in income tax expense primarily due to a reduction in the corporate income tax rate resulting from the TCJA in 2018; and

• a $10 million increase in interest expense due to higher outstanding other long-term debt.

These decrease in net income were partially offset by the following:

• a $5 million decrease in non-service cost components of net periodic pension and post-retirement costs included in Other expense, net shown above; and

• an $8 million increase in TDU operating income resulting from a $7 million increase discussed below in Results of Operations by Reportable Segment and increased usage of $1 million, primarily due to a return to more normal weather, which was not offset by the weather hedge loss recorded on CenterPoint Energy.

Income Tax Expense.  Houston Electric reported an effective tax rate of 21% and (2)% for the years ended December 31, 2018 and 2017, respectively. The effective tax rate of 21% is primarily due to the reduction in the federal corporate income tax rate from 35% to 21% effective January 1, 2018 as prescribed by the TCJA and the amortization of EDIT. See Note 15 to the consolidated financial statements for a more in-depth discussion of the 2018 impacts of the TCJA.

CERC CONSOLIDATED RESULTS OF OPERATIONS

CERC’s results of operations are affected by seasonal fluctuations in the demand for natural gas and price movements of energy commodities as well as natural gas basis differentials. CERC’s results of operations are also affected by, among other things, the actions of various federal, state and local governmental authorities having jurisdiction over rates CERC charges, competition in CERC’s various business operations, the effectiveness of CERC’s risk management activities, debt service costs and income tax expense.

	Year Ended December 31,
	2019			2018			2017
	(in millions)
Revenues	$	6,570		$	7,343		$	6,603
Expenses	6,220			7,121			6,136
Operating Income	350			222			467
Interest and other finance charges	(116		)	(122		)	(123		)
Other expense, net	(8		)	(8		)	(25		)
Income from continuing operations before income taxes	226			92			319
Income tax expense (benefit)	14			22			(265		)
Income from continuing operations	212			70			584
Income from discontinued operations, net of tax	—			138			161
Net Income	$	212		$	208		$	745

2019 Compared to 2018

Net Income.  CERC reported net income of $212 million for 2019 compared to $208 million for 2018.

The increase in net income of $4 million was primarily due to the following key factors:

• a $128 million increase in operating income discussed below in Results of Operations by Reportable Segment;

• an $8 million decrease in income tax expense due to the lower effective tax rate, as explained below, partially offset by higher income from continuing operations ; and

• a $6 million decrease in interest and other finance charges.

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These increases were partially offset by a $138 million decrease in income from discontinued operations, net of tax, discussed further in Notes 11 and 15 to the consolidated financial statements.

Income Tax Expense. CERC’s effective tax rate reported on income from continuing operations was 6% and 24% for the years ended December 31, 2019 and 2018, respectively. The lower effective tax rate of 6% on income from continuing operations is due to an increase in the amount of amortization of the net regulatory EDIT liability as decreed by regulators in certain jurisdictions, the effect of state law changes that resulted in the remeasurement of state deferred taxes, and the impact of the reduction in valuation allowances on certain state net operating losses that are now expected to be realized.

2018 Compared to 2017

Net Income.  CERC reported net income of $208 million for 2018 compared to net income of $745 million for 2017.

The decrease in net income of $537 million was primarily due to the following key factors:

• a $287 million increase in income tax expense, resulting from a reduction in income tax expense of $396 million due to tax reform in 2017, discussed further in Note 15 to the consolidated financial statements, offset by a $109 million decrease in income tax expense primarily due to lower income from continuing operations and a reduction in the corporate income tax rate resulting from the TCJA in 2018;

• a $245 million decrease in operating income, discussed below by reportable segment in Results of Operations by Reportable Segment; and

• a $23 million decrease in income from discontinued operations, net of tax, due to the Internal Spin discussed further in Note 11 to the consolidated financial statements.

These decreases were partially offset by:

• a $12 million decrease in the non-service cost components of net periodic pension and post-retirement costs included in Other expense, net shown above;

• a $5 million increase in miscellaneous other non-operating income included in Other expense, net shown above; and

• a $1 million decrease in interest expense due to lower outstanding long-term debt.

Income Tax Expense. CERC’s effective tax rate reported on income from continuing operations was 24% and (83)% for the years ended December 31, 2018 and 2017, respectively. The effective tax rate of 24% on income from continuing operations is primarily due to the reduction in the federal corporate income tax rate from 35% to 21% effective January 1, 2018 as prescribed by the TCJA and the amortization of EDIT. See Note 15 to the consolidated financial statements for a more in-depth discussion of the 2018 impacts of the TCJA.

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RESULTS OF OPERATIONS BY REPORTABLE SEGMENT

The following table presents operating income (loss) for each reportable segment for 2019, 2018 and 2017. Included in revenues by reportable segment below are intersegment sales, which are accounted for as if the sales were to third parties at current market prices. These revenues are eliminated during consolidation. See Note 19 to the consolidated financial statements for details of reportable segments by registrant.

Operating Income (Loss) by Reportable Segment

	Year Ended December 31,
	2019			2018			2017
	(in millions)
CenterPoint Energy
Houston Electric T&D (1)	$	624		$	623		$	636
Indiana Electric Integrated	90			—			—
Natural Gas Distribution	408			266			348
Energy Services (2)	32			(47		)	126
Infrastructure Services (3)	95			—			—
Corporate and Other	(23		)	(11		)	26
Total CenterPoint Energy Consolidated Operating Income	$	1,226		$	831		$	1,136
Houston Electric
Houston Electric T&D (1)	$	618		$	625		$	637
CERC
Natural Gas Distribution	$	316		$	266		$	348
Energy Services (2)	32			(47		)	126
Other Operations	2			3			(7		)
Total CERC Consolidated Operating Income	$	350		$	222		$	467

(1) Operating income for CenterPoint Energy’s Houston Electric T&D reportable segment differs from operating income for Houston Electric due to weather hedge gains (losses) recorded at CenterPoint Energy that are not recorded at Houston Electric. Weather hedge gains (losses) of $6 million, $(2) million and $(1) million were recorded at CenterPoint Energy’s Houston Electric T&D reportable segment for the years ended December 31, 2019, 2018 and 2017, respectively. See Note 9(a) to the consolidated financial statements for more information on the weather hedge.

(2) 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. The transaction is expected to close in the second quarter of 2020. For further information, see Notes 6 and 23 to the consolidated financial statements.

(3) 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 is expected to close in the second quarter of 2020. For further information, see Notes 6 and 23 to the consolidated financial statements.

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Houston Electric T&D (CenterPoint Energy and Houston Electric)

The following table provides summary data of the Houston Electric T&D reportable segment:

	Year Ended December 31,
	2019		2018		2017
Revenues:	(in millions, except throughput and customer data)
TDU	$	2,684	$	2,638	$	2,588
Bond Companies	312		594		409
Total revenues	2,996		3,232		2,997
Expenses:
Operation and maintenance, excluding Bond Companies	1,470		1,444		1,397
Depreciation and amortization, excluding Bond Companies	377		386		395
Taxes other than income taxes	247		240		235
Bond Companies	278		539		334
Total expenses	2,372		2,609		2,361
Operating Income (1)	$	624	$	623	$	636
Operating Income:
TDU	$	590	$	568	$	561
Bond Companies (2)	34		55		75
Total segment operating income	$	624	$	623	$	636
Throughput (in GWh):
Residential	30,334		30,405		29,703
Total	92,180		90,409		88,636
Number of metered customers at end of period:
Residential	2,243,188		2,198,225		2,164,073
Total	2,534,286		2,485,370		2,444,299

(1) Operating income for CenterPoint Energy’s Houston Electric T&D reportable segment differs from operating income for Houston Electric due to weather hedge gains (losses) recorded at CenterPoint Energy that are not recorded at Houston Electric. Weather hedge gains (losses) of $6 million, $(2) million and $(1) million were recorded at CenterPoint Energy’s Houston Electric T&D reportable segment for the years ended December 31, 2019, 2018 and 2017, respectively. See Note 9(a) to the consolidated financial statements for more information on the weather hedge.

(2) Operating income from the Bond Companies, together with $5 million, $4 million and $2 million of interest income for the years ended December 31, 2019, 2018 and 2017, respectively, are necessary to pay interest on the Securitization Bonds.

2019 Compared to 2018.  The Houston Electric T&D reportable segment reported operating income of $624 million for 2019, consisting of $590 million from the TDU and $34 million related to the Bond Companies. For 2018, operating income totaled $623 million, consisting of $568 million from the TDU and $55 million related to the Bond Companies.

TDU operating income increased $22 million primarily due to the following key factors:

• higher transmission-related revenues of $74 million, exclusive of the TCJA impact mentioned below, partially offset by higher transmission costs billed by transmission providers of $57 million;

• decreased operation and maintenance expenses of $34 million, net of $10 million of Merger-related severance costs and $12 million of write offs for rate case expenses associated with the settlement of Houston Electric’s rate case, primarily due to lower labor and benefits costs and lower support services costs;

• customer growth of $28 million from the addition of over 48,000 customers;

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• rate increases of $20 million related to distribution capital investments, exclusive of the TCJA impact mentioned below; and

• higher miscellaneous revenues of $14 million primarily related to right-of-way revenues.

The increase in operating income was partially offset by the following:

• lower equity return of $29 million, primarily related to the annual true-up of transition charges to correct over-collections that occurred during the preceding 12 months and due to the winding up of Transition Bond Company II;

• higher depreciation and amortization expense, primarily because of ongoing additions to plant in service, and other taxes of $26 million;

• lower usage of $20 million due to lower residential use per customer and lower demand in our large commercial and small industrial classes in part due to less favorable weather in early 2019; and

• lower revenue of $15 million related to the impact of the TCJA.

Lower depreciation and amortization expenses related to AMS of $28 million were offset by a corresponding decrease in related revenues.

2018 Compared to 2017.  The Houston Electric T&D reportable segment reported operating income of $623 million for 2018, consisting of $568 million from the TDU and $55 million related to the Bond Companies. For 2017, operating income totaled $636 million, consisting of $561 million from the TDU and $75 million related to the Bond Companies.

TDU operating income increased $7 million primarily due to the following key factors:

• higher transmission-related revenues of $37 million, exclusive of the TCJA impact, and lower transmission costs billed by transmission providers of $32 million;

• customer growth of $31 million from the addition of over 41,000 customers;

• rate increases of $36 million related to distribution capital investments, exclusive of the TCJA;

• higher equity return of $32 million, primarily related to the annual true-up of transition charges correcting for under-collections that occurred during the preceding 12 months;

• higher miscellaneous revenues of $9 million largely due to right-of-way and fiber and wireless revenues; and

• higher usage of $8 million, primarily due to a return to more normal weather.

The increase to operating income was partially offset by the following:

• increased operation and maintenance expenses of $79 million, excluding transmission costs billed by transmission providers, primarily due to the following:

◦ contract services of $24 million, largely due to increased resiliency spend and services related to fiber and wireless;

◦ support services of $23 million, primarily related to technology projects;

◦ labor and benefits costs of $14 million;

◦ other miscellaneous operation and maintenance expenses of $12 million; and

◦ damage claims from third parties of $6 million;

• lower revenues of $79 million due to the recording of a regulatory liability and a corresponding decrease to revenue of $31 million reflecting the difference in revenues collected under customer rates at the pre-TCJA tax rate and the revenues

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that would have been collected had rates been adjusted to the lower corporate tax rate upon TCJA enactment and lower revenues of $48 million due to lower transmission and distribution rate filings as a result of the TCJA; and

• higher depreciation and amortization expense, primarily because of ongoing additions to plant in service, and other taxes of $17 million.

Lower depreciation and amortization expenses related to AMS of $21 million were offset by a corresponding decrease in related revenues.

Indiana Electric Integrated (CenterPoint Energy)

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

	Year Ended  December 31, 2019 (1)
	(in millions, except throughput and customer data)
Revenues	$	523
Expenses:
Utility natural gas, fuel and purchased power	149
Operation and maintenance	179
Depreciation and amortization	91
Taxes other than income taxes	14
Total expenses	433
Operating Income	$	90
Throughput (in GWh):
Retail	4,310
Wholesale	376
Total	4,686
Number of metered customers at end of period:
Residential	128,947
Total	147,942

(1) Represents February 1, 2019 through December 31, 2019 results only due to the Merger.

2019 Compared to 2018. The Indiana Electric Integrated reportable segment reported operating income of $90 million for 2019, which includes operation and maintenance expenses of $21 million for Merger-related severance and incentive compensation costs. These results are not comparable to 2018 as this reportable segment was acquired in the Merger as discussed in Note 4 to the consolidated financial statements.

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Natural Gas Distribution (CenterPoint Energy)

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

	Year Ended December 31,
	2019		2018		2017
	(in millions, except throughput and customer data)
Revenues	$	3,683	$	2,967	$	2,639
Expenses:
Utility natural gas, fuel and purchased power	1,617		1,467		1,164
Operation and maintenance	1,036		803		722
Depreciation and amortization	417		277		260
Taxes other than income taxes	205		154		145
Total expenses	3,275		2,701		2,291
Operating Income	$	408	$	266	$	348
Throughput (in Bcf):
Residential	246		186		151
Commercial and industrial	458		285		261
Total Throughput	704		471		412
Number of customers at end of period:
Residential	4,252,361		3,246,277		3,213,140
Commercial and industrial	349,749		260,033		256,651
Total	4,602,110		3,506,310		3,469,791

2019 Compared to 2018.  CenterPoint Energy’s Natural Gas Distribution reportable segment reported operating income of $408 million for 2019 compared to $266 million for 2018.

Operating income increased $142 million primarily as a result of the following key factors:

• a $91 million increase in operating income associated with the natural gas businesses acquired in the Merger for the period from February 1, 2019 through December 31, 2019, which includes $45 million in Merger-related severance and incentive compensation costs, as well as the addition of over 1 million customers in Indiana and Ohio;

• a $30 million increase in revenues for weather and usage, partially driven by the timing of a decoupling mechanism in Minnesota in CERC’s NGD service territory;

• a $14 million increase in revenues associated with customer growth from the addition of over 42,000 new customers in CERC’s NGD service territories;

• a $12 million increase in rates, exclusive of the TCJA impacts discussed below, from rate filings in CERC’s NGD service territories; and

• a $6 million increase in revenue due to a reduction in TCJA-related revenue offsets that were recorded in 2018 in CERC’s NGD service territories.

The increase in operating income was partially offset by the following:

• increased depreciation and amortization expense of $13 million, due to ongoing additions to plant-in-service in CERC’s NGD service territories; and

• higher operation and maintenance expenses of $1 million, consisting of $10 million of Merger-related severance and incentive compensation costs associated with CERC’s NGD, which were offset by a $9 million decline in materials and supplies, contracts and services and bad debt expenses.

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Decreased operation and maintenance expense related to energy efficiency programs of $14 million and increased other taxes expense related to gross receipt taxes of $2 million were offset by a corresponding decrease and increase in the related revenues in CERC’s NGD service territories, respectively.

2018 Compared to 2017.  CenterPoint Energy’s Natural Gas Distribution reportable segment reported operating income of $266 million for 2018 compared to $348 million for 2017.

Operating income decreased $82 million primarily as a result of the following key factors:

• lower revenue of $47 million, associated with the recording of a regulatory liability and a corresponding decrease to revenue in certain jurisdictions of $14 million reflecting the difference in revenues collected under customer rates at the pre-TCJA tax rates and the revenues that would have been collected had rates been adjusted to the lower corporate tax rate upon TCJA enactment and lower filing amounts of $33 million associated with the lower corporate tax rate as a result of the TCJA in CERC’s NGD service territories;

• higher operation and maintenance expenses of $41 million in CERC’s NGD service territories, primarily consisting of:

◦ materials and supplies, contracts and services and bad debt expenses of $15 million;

◦ support services expenses of $16 million, primarily related to technology projects;

◦ and other miscellaneous operation and maintenance expenses of $10 million;

• higher labor and benefits costs of $30 million, resulting from the recording in 2017 of regulatory assets (and a corresponding reduction in expense) to recover $16 million of prior post-retirement expenses in future rates established in the Texas Gulf rate order and additional maintenance activities in CERC’s NGD service territories;

• increased depreciation and amortization expense of $17 million, primarily due to ongoing additions to plant-in-service in CERC’s NGD service territories;

• decreased revenue of $10 million, primarily driven by timing of weather normalization adjustments in CERC’s NGD service territories; and

• higher other taxes of $2 million, primarily due to higher property taxes in CERC’s NGD service territories.

The decrease in operating income was partially offset by:

• rate increases of $46 million, primarily in the Texas, Minnesota and Arkansas jurisdictions, exclusive of the TCJA impact discussed above in CERC’s NGD service territories;

• an increase in non-volumetric revenues of $10 million in CERC’s NGD service territories; and

• a $10 million increase associated with customer growth from the addition of over 36,000 customers in CERC’s NGD service territories.

Increased operation and maintenance expense related to energy efficiency programs of $10 million and increased other taxes expense related to gross receipt taxes of $7 million were offset by a corresponding increase in the related revenues in CERC’s NGD service territories.

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Natural Gas Distribution (CERC)

The following table provides summary data of CERC’s Natural Gas Distribution reportable segment: 

	Year Ended December 31,
	2019		2018		2017
	(in millions, except throughput and customer data)
Revenues	$	2,951	$	2,967	$	2,639
Expenses:
Natural gas	1,395		1,467		1,164
Operation and maintenance	790		803		722
Depreciation and amortization	289		277		260
Taxes other than income taxes	161		154		145
Total expenses	2,635		2,701		2,291
Operating Income	$	316	$	266	$	348
Throughput (in Bcf):
Residential	188		186		151
Commercial and industrial	292		285		261
Total Throughput	480		471		412
Number of customers at end of period:
Residential	3,287,343		3,246,277		3,213,140
Commercial and industrial	260,872		260,033		256,651
Total	3,548,215		3,506,310		3,469,791

2019 Compared to 2018.  CERC’s Natural Gas Distribution reportable segment reported operating income of $316 million for 2019 compared to $266 million for 2018.

Operating income increased $50 million primarily as a result of the following key factors:

• a $30 million increase in revenues for weather and usage, partially driven by the timing of a decoupling mechanism in Minnesota;

• a $14 million increase in revenues associated with customer growth from the addition of over 42,000 new customers;

• a $12 million increase in rates, exclusive of the TCJA impacts discussed below; and

• a $6 million increase in revenue due to a reduction in TCJA-related revenue offsets that were recorded in 2018.

The increase in operating income was partially offset by the following:

• increased depreciation and amortization expense of $13 million, due to ongoing additions to plant-in-service in CERC’s NGD service territories; and

• higher operation and maintenance expenses of $1 million, consisting of $10 million of Merger-related severance and incentive compensation costs, which were offset by a $9 million decline in materials and supplies, contracts and services and bad debt expenses.

Decreased operation and maintenance expense related to energy efficiency programs of $14 million and increased other taxes expense related to gross receipt taxes of $2 million were offset by a corresponding decrease and increase in the related revenues, respectively.

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2018 Compared to 2017.  The CERC’s Natural Gas Distribution reportable segment reported operating income of $266 million for 2018 compared to $348 million for 2017.

Operating income decreased $82 million primarily as a result of the following key factors:

• lower revenue of $47 million, associated with the recording of a regulatory liability and a corresponding decrease to revenue in certain jurisdictions of $14 million reflecting the difference in revenues collected under customer rates at the pre-TCJA tax rates and the revenues that would have been collected had rates been adjusted to the lower corporate tax rate upon TCJA enactment and lower filing amounts of $33 million associated with the lower corporate tax rate as a result of the TCJA;

• higher operation and maintenance expenses of $41 million, primarily consisting of:

◦ materials and supplies, contracts and services and bad debt expenses of $15 million;

◦ support services expenses of $16 million, primarily related to technology projects;

◦ and other miscellaneous operation and maintenance expenses of $10 million;

• higher labor and benefits costs of $30 million, resulting from the recording in 2017 of regulatory assets (and a corresponding reduction in expense) to recover $16 million of prior post-retirement expenses in future rates established in the Texas Gulf rate order and additional maintenance activities;

• increased depreciation and amortization expense of $17 million, primarily due to ongoing additions to plant-in-service;

• decreased revenue of $10 million, primarily driven by timing of weather normalization adjustments; and

• higher other taxes of $2 million, primarily due to higher property taxes.

The decrease in operating income was partially offset by:

• rate increases of $46 million, primarily in the Texas, Minnesota and Arkansas jurisdictions, exclusive of the TCJA impact discussed above;

• an increase in non-volumetric revenues of $10 million; and

• a $10 million increase associated with customer growth from the addition of over 36,000 customers.

Increased operation and maintenance expense related to energy efficiency programs of $10 million and increased other taxes expense related to gross receipt taxes of $7 million were offset by a corresponding increase in the related revenues.

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Energy Services (CenterPoint Energy and CERC)

The following table provides summary data of the Energy Services reportable segment:

	Year Ended December 31,
	2019		2018			2017
	(in millions, except throughput and customer data)
Revenues	$	3,782	$	4,521		$	4,049
Expenses:
Natural gas	3,588		4,453			3,816
Operation and maintenance	96		96			86
Depreciation and amortization	16		16			19
Taxes other than income taxes	2		3			2
Goodwill impairment	48		—			—
Total expenses	3,750		4,568			3,923
Operating Income (Loss)	$	32	$	(47	)	$	126
Timing impacts related to mark-to-market gain (loss) (1)	$	39	$	(110	)	$	79
Throughput (in Bcf)	1,305		1,355			1,200
Number of customers at end of period (2)	31,000		30,000			31,000

(1) Includes the change in unrealized mark-to-market value and the impact from derivative assets and liabilities acquired through the purchase of Continuum and AEM.

(2) These numbers do not include approximately 66,000, 65,000 and 72,000 natural gas customers as of December 31, 2019, 2018 and 2017, respectively, that are under residential and small commercial choice programs invoiced by their host utility.

2019 Compared to 2018. The Energy Services reportable segment reported operating income of $32 million for 2019 compared to an operating loss of $47 million for 2018.

Operating income increased $79 million as a result of the following:

• a $149 million increase from mark-to-market accounting for derivatives associated with certain natural gas purchases and sales used to lock in economic margins.

The increase in operating income was partially offset by the following:

• a $48 million goodwill impairment charge. See Note 6 to the consolidated financial statements for further information; and

• a $22 million decrease in margin due to fewer opportunities to optimize natural gas costs relative to 2018, primarily in the first quarter of 2019. Weather-driven market impacts in various regions of the continental United States provided increased margins during the first quarter of 2018 which were not repeated in 2019.

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. The transaction is expected to close in the second quarter of 2020. For further information, see Notes 6 and 23 to the consolidated financial statements.

2018 Compared to 2017. The Energy Services reportable segment reported an operating loss of $47 million for 2018 compared to operating income of $126 million for 2017.

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Operating income decreased $173 million as a result of the following key factors:

• a $189 million decrease from mark-to-market accounting for derivatives associated with certain natural gas purchases and sales used to lock in economic margins; and

• a $10 million increase in operation and maintenance expenses, attributable to increased technology expenses, higher contract and services expense related to pipeline integrity testing, higher support services and legal expenses.

The decrease in operating income was partially offset by the following:

• a $22 million increase in margin due to increased opportunities to optimize natural gas supply costs through storage and transportation capacity, primarily in the first quarter of 2018, and incremental volumes from customers. Realized commercial opportunities attributable to the Continuum and AEM acquisitions and colder than normal weather in several regions of the United States, primarily in the first quarter of 2018, drove incremental sales volumes; and

• a $5 million increase in margin due to increased revenues from energy delivery to customers through CEIP interconnect projects and MES’ portable natural gas supply services.

Infrastructure Services (CenterPoint Energy)

The following table provides summary data of the Infrastructure Services reportable segment:

	Year Ended  December 31, 2019 (1)
	(in millions, except throughput and customer data)
Revenues	$	1,190
Expenses:
Non-utility cost of revenues, including natural gas	309
Operation and maintenance	734
Depreciation and amortization	50
Taxes other than income taxes	2
Total expenses	1,095
Operating Income	$	95
Backlog at period end (2):
Blanket contracts (3)	$	628
Bid contracts (4)	254
Total	$	882

(1) Represents February 1, 2019 through December 31, 2019 results only due to the Merger.

(2) Backlog represents the amount of revenue Infrastructure Services expects to realize from work to be performed on uncompleted contracts in the next twelve months, including new contractual agreements on which work has not begun. Infrastructure Services operates primarily under two types of contracts, blanket contracts and bid contracts.

(3) Under blanket contracts, customers are not contractually committed to specific volumes of services; however, Infrastructure Services expects to be chosen to perform work needed by a customer in a given time frame. These contracts are typically awarded on an annual or multi-year basis. For blanket work, backlog represents an estimate of the amount of revenue that Infrastructure Services expects to realize from work to be performed in the next twelve months on existing contracts or contracts management expects to be renewed or awarded.

(4) Using bid contracts, customers are contractually committed to a specific service to be performed for a specific price, whether in total for a project or on a per unit basis.

2019 Compared to 2018. The Infrastructure Services reportable segment reported operating income of $95 million for 2019, which includes $13 million for Merger-related severance and incentive compensation costs, $19 million of Merger-related

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amortization of intangibles for construction backlog recorded in Non-utility cost of revenues, including natural gas, and $11 million of Merger-related intangibles amortization recorded in depreciation and amortization. These results are not comparable to 2018 as this reportable segment was acquired in the Merger as discussed in Note 4 to the consolidated financial statements.

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 is expected to close in the second quarter of 2020. For further information, see Notes 6 and 23 to the consolidated financial statements.

Midstream Investments (CenterPoint Energy)

The following table provides pre-tax equity income of the Midstream Investments reportable segment:

	Year Ended December 31,
	2019		2018		2017
	(in millions)
Equity earnings from Enable, net (1)	$	229	$	307	$	265

(1) Equity earnings from Enable, net for the year ended December 31, 2019 were reduced by CenterPoint Energy’s share, $46 million, of Enable’s goodwill impairment charge of $86 million recorded in the fourth quarter of 2019.

Corporate and Other (CenterPoint Energy)

The following table shows the operating income (loss) of CenterPoint Energy’s Corporate and Other reportable segment:

	Year Ended December 31,
	2019			2018			2017
	(in millions)
Revenues	$	300		$	15		$	14
Expenses:
Non-utility cost of revenues, including natural gas	218			—			—
Operation and maintenance	32			(16		)	(54		)
Depreciation and amortization	66			33			33
Taxes other than income taxes	7			9			9
Total expenses	323			26			(12		)
Operating Income (Loss)	$	(23	)	$	(11	)	$	26

2019 Compared to 2018. CenterPoint Energy’s Corporate and Other reportable segment reported an operating loss of $23 million for 2019 compared to an operating loss of $11 million for 2018.

Operating loss increased $12 million primarily due to a $20 million increase in operation and maintenance expenses for Merger-related transaction and integration costs incurred by CenterPoint Energy corporate.

The increase in operating loss was partially offset by:

• operating income of $4 million associated with ESG, which was acquired in the Merger, for the period February 1, 2019 through December 31, 2019, including $2 million for Merger-related severance and incentive compensation costs, $5 million of Merger-related amortization of intangibles recorded in non-utility cost of revenues, including natural gas and $5 million of Merger-related intangibles amortization recorded in depreciation and amortization; and

• a $3 million property tax refund.

2018 Compared to 2017. CenterPoint Energy’s Corporate and Other reportable segment reported an operating loss of $11 million for 2018 compared to operating income of $26 million for 2017. Operating income decreased $37 million primarily due to costs related to the Merger.

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Corporate and Other (CERC)

The following table shows the operating income (loss) of CERC’s Corporate and Other reportable segment:

	Year Ended December 31,
	2019		2018			2017
	(in millions)
Revenues	$	5	$	1		$	—
Expenses	3		(2		)	7
Operating Income (Loss)	$	2	$	3		$	(7	)

LIQUIDITY AND CAPITAL RESOURCES

Historical Cash Flows

The net cash provided by (used in) operating, investing and financing activities for 2019, 2018 and 2017 is as follows:

	Year Ended December 31,
	2019									2018									2017
	CenterPoint Energy			Houston Electric			CERC			CenterPoint Energy			Houston Electric			CERC			CenterPoint Energy			Houston Electric			CERC
	(in millions)
Cash provided by (used in):
Operating activities	$	1,638		$	918		$	466		$	2,136		$	1,115		$	814		$	1,417		$	905		$	278
Investing activities	(8,421		)	(1,495		)	(662		)	(1,207		)	(911		)	(697		)	(1,257		)	(776		)	(346		)
Financing activities	2,776			442			173			3,053			(108		)	(104		)	(245		)	(236		)	79

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

	Year Ended December 31,
	2019 compared to 2018									2018 compared to 2017
	CenterPoint Energy			Houston  Electric			CERC			CenterPoint Energy			Houston Electric			CERC
	(in millions)
Changes in net income after adjusting for non-cash items	$	299		$	(234	)	$	180		$	(63	)	$	154		$	(243	)
Changes in working capital	(856		)	60			(307		)	604			57			595
Change in equity in earnings of unconsolidated affiliates	77			—			—			(42		)	—			—
Change in distributions from unconsolidated affiliates (1)	(6		)	—			—			267			—			—
Changes related to discontinued operations (2)	—			—			(176		)	—			—			176
Higher pension contribution	(40		)	—			—			(21		)	—			—
Other	28			(23		)	(45		)	(26		)	(1		)	8
	$	(498	)	$	(197	)	$	(348	)	$	719		$	210		$	536

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

(2) See Notes 2(c) and 11 to the consolidated financial statements for a discussion of CERC’s discontinued operations.

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

	Year Ended December 31,
	2019 compared to 2018									2018 compared to 2017
	CenterPoint Energy			Houston  Electric			CERC			CenterPoint Energy			Houston Electric			CERC
	(in millions)
Proceeds from the sale of marketable securities	$	(398	)	$	—		$	—		$	398		$	—		$	—
Proceeds from the sale of assets	5			—			—			—			—			—
Purchase of investments	(6		)	—			—			—			—			—
Acquisitions, net of cash acquired	(5,991		)	—			—			132			—			132
Net change in capital expenditures (1)	(855		)	(103		)	(143		)	(225		)	(47		)	(120		)
Net change in notes receivable from unconsolidated affiliates	—			(481		)	228			—			(96		)	(114		)
Change in distributions from Enable in excess of cumulative earnings	12			—			—			(267		)	—			—
Changes related to discontinued operations (2)	—			—			(47		)	—			—			(250		)
Other	19			—			(3		)	12			8			1
	$	(7,214	)	$	(584	)	$	35		$	50		$	(135	)	$	(351	)

(1) The increase in capital expenditures in 2019 primarily resulted from businesses acquired in the Merger.

(2) See Notes 2(c) and 11 to the consolidated financial statements for a discussion of CERC’s discontinued operations.

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

	Year Ended December 31,
	2019 compared to 2018									2018 compared to 2017
	CenterPoint Energy			Houston  Electric			CERC			CenterPoint Energy			Houston Electric			CERC
	(in millions)
Net changes in commercial paper outstanding	$	3,434		$	—		$	855		$	(1,892	)	$	—		$	(1,017	)
Proceeds from issuances of preferred stock	(1,740		)	—			—			1,740			—			—
Proceeds from issuance of Common Stock	(1,844		)	—			—			1,844			—			—
Net changes in long-term debt outstanding, excluding commercial paper	(397		)	274			(599		)	2,126			77			851
Net changes in reacquired debt	—			—			—			5			—			5
Net changes in debt issuance costs	27			(4		)	5			(34		)	(1		)	(1		)
Net changes in short-term borrowings	39			—			39			(43		)	—			(43		)
Distributions to ZENS note holders	398			—			—			(398		)	—			—
Increased payment of Common Stock dividends	(78		)	—			—			(38		)	—			—
Increased payment of preferred stock dividends	(107		)	—			—			(11		)	—			—
Net change in notes payable from affiliated companies	—			58			570			—			(119		)	(1,140		)
Contribution from parent	—			390			(831		)	—			200			922
Dividend to parent	—			(167		)	240			—			(29		)	241
Other	(9		)	(1		)	(2		)	(1		)	—			(1		)
	$	(277	)	$	550		$	277		$	3,298		$	128		$	(183	)

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Future Sources and Uses of Cash

The liquidity and capital requirements of the Registrants are affected primarily by results of operations, capital expenditures, debt service requirements, tax payments, working capital needs and various regulatory actions. Capital expenditures are expected to be used for investment in infrastructure for electric and natural gas distribution operations. These capital expenditures are anticipated to maintain reliability and safety, increase resiliency and expand our systems through value-added projects. In addition to dividend payments on CenterPoint Energy’s Series A Preferred Stock, Series B Preferred Stock and Common Stock, and in addition to interest payments on debt, the Registrants’ principal anticipated cash requirements for 2020 include the following:

	CenterPoint Energy		Houston Electric		CERC
	(in millions)
Estimated capital expenditures	$	2,630	$	1,031	$	702
Scheduled principal payments on Securitization Bonds	231		231		—
Minimum contributions to pension plans and other post-retirement plans	100		9		3
Maturing Vectren term loans	600		—		—

The Registrants expect that anticipated 2020 cash needs will be met with borrowings under their credit facilities, proceeds from the issuance of long-term debt, term loans or common stock, anticipated cash flows from operations, with respect to CenterPoint Energy and CERC, proceeds from commercial paper and with respect to CenterPoint Energy, distributions from Enable. Additionally, proceeds from the expected closing of the transactions underlying the Securities Purchase Agreement and Equity Purchase Agreement will be used to repay outstanding debt. Discretionary financing or refinancing may result in the issuance of equity securities of CenterPoint Energy or debt securities of the Registrants in the capital markets or the arrangement of additional credit facilities or term bank loans. Issuances of equity or debt in the capital markets, funds raised in the commercial paper markets and additional credit facilities may not, however, be available on acceptable terms.

The following table sets forth the Registrants’ actual capital expenditures by reportable segment for 2019 and estimates of the Registrants’ capital expenditures currently planned for projects for 2020 through 2024: 

	2019		2020		2021		2022		2023		2024
CenterPoint Energy	(in millions)
Houston Electric T&D	$	1,033	$	1,031	$	1,082	$	934	$	934	$	876
Indiana Electric Integrated (1)	183		276		268		267		396		392
Natural Gas Distribution (1)	1,098		1,124		1,037		1,261		1,373		1,331
Energy Services (3)	12		4		—		—		—		—
Infrastructure Services (1) (4)	67		28		—		—		—		—
Corporate and Other (1)	194		167		136		123		92		92
Total	$	2,587	$	2,630	$	2,523	$	2,585	$	2,795	$	2,691
Houston Electric (2)	$	1,033	$	1,031	$	1,082	$	934	$	934	$	876
CERC
Natural Gas Distribution	$	773	$	698	$	648	$	850	$	917	$	891
Energy Services (3)	12		4		—		—		—		—
Total	$	785	$	702	$	648	$	850	$	917	$	891

(1) Included in the 2019 column are capital expenditures from businesses acquired in the Merger, for the period February 1, 2019 to December 31, 2019.

(2) Houston Electric consists of a single reportable segment, Houston Electric T&D.

(3) 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. The transaction is expected to close in the second quarter of 2020. For further information, see Notes 6 and 23 to the consolidated financial statements.

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(4) 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 is expected to close in the second quarter of 2020. For further information, see Notes 6 and 23 to the consolidated financial statements.

The following table sets forth estimates of the Registrants’ contractual obligations as of December 31, 2019, including payments due by period:

Contractual Obligations	Total		2020		2021-2022		2023-2024		2025 and thereafter
	(in millions)
CenterPoint Energy
Securitization Bonds	$	977	$	231	$	430	$	316	$	—
Other long-term debt (1)	14,191		600		5,633		1,579		6,379
Interest payments — Securitization Bonds (2)	79		30		37		12		—
Interest payments — other long-term debt (2)	6,195		529		871		701		4,094
Operating leases (3)	69		22		25		10		12
Benefit obligations (4)	—		—		—		—		—
Non-trading derivative liabilities	80		51		26		3		—
Commodity and other commitments (5)	4,279		750		1,035		606		1,888
Total contractual cash obligations (6)	$	25,870	$	2,213	$	8,057	$	3,227	$	12,373
Houston Electric
Securitization Bonds	$	977	$	231	$	430	$	316	$	—
Other long-term debt (1)	3,973		—		702		200		3,071
Interest payments — Securitization Bonds (2)	79		30		37		12		—
Interest payments — other long-term debt (2)	2,896		161		300		267		2,168
Operating leases (3)	1		1		—		—		—
Benefit obligations (4)	—		—		—		—		—
Total contractual cash obligations (6)	$	7,926	$	423	$	1,469	$	795	$	5,239
CERC
Long-term debt	$	2,546	$	—	$	969	$	300	$	1,277
Interest payments — long-term debt (1)	1,379		112		179		141		947
Operating leases (3)	28		6		8		5		9
Benefit obligations (4)	—		—		—		—		—
Non-trading derivative liabilities	58		44		14		—		—
Commodity and other commitments (5)	3,089		533		674		356		1,526
Total contractual cash obligations (6)	$	7,100	$	695	$	1,844	$	802	$	3,759

(1) ZENS obligations are included in the 2025 and thereafter column at their contingent principal amount of $75 million as of December 31, 2019 . These obligations are exchangeable for cash at any time at the option of the holders for 95% of the current value of the reference shares attributable to each ZENS ($822 million as of December 31, 2019), as discussed in Note 12 to the consolidated financial statements.  

(2) The Registrants calculated estimated interest payments for long-term debt as follows: for fixed-rate debt and term debt, the Registrants calculated interest based on the applicable rates and payment dates; for variable-rate debt and/or non-term debt, the Registrants used interest rates in place as of December 31, 2019. The Registrants typically expect to settle such interest payments with cash flows from operations and short-term borrowings.

(3) For a discussion of operating leases, please read Note 22 to the consolidated financial statements.

(4) See Note 8(g) to the consolidated financial statements for information on the Registrants’ expected contributions to pension plans and other postretirement plans in 2020.

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(5) For a discussion of commodity and other commitments, please read Note 16(a) to the consolidated financial statements.

(6) This table does not include estimated future payments for expected future AROs. These payments are primarily estimated to be incurred after 2025. See Note 3(c) to the consolidated financial statements for further information.

Off-Balance Sheet Arrangements

Other than Houston Electric’s first mortgage bonds and general mortgage bonds issued as collateral for tax-exempt long-term debt of CenterPoint Energy (see Note 14 to the consolidated financial statements) and operating leases, the Registrants have no off-balance sheet arrangements.

Regulatory Matters

Houston Electric Base Rate Case (CenterPoint Energy and Houston Electric)

On April 5, 2019, and subsequently adjusted in errata filings in May and June 2019, Houston Electric filed its base rate application with the PUCT and the cities in its service area to change its rates, seeking approval for revenue increases of approximately $194 million, excluding a rider to refund approximately $40 million annually over three years discussed below. This rate filing is based on a rate base of $6.4 billion, a 50% debt/50% equity capital structure and a 10.4% ROE. Houston Electric last filed for a base rate increase on June 30, 2010, with a test year ending December 31, 2009. Houston Electric also requested a prudency determination on all capital investments made since January 1, 2010, the establishment of a rider to refund over three years to its customers approximately $119 million of unprotected EDIT resulting from the TCJA, updated depreciation rates and approval to clarify and update various non-rate tariff provisions. Recovery of all reasonable and necessary rate case expenses for this case and certain prior rate case proceedings were severed into a separate proceeding. A hearing was held June 24–28, 2019.

On September 16, 2019, the ALJs issued a PFD. The PUCT began deliberating on the PFD (which is prepared by ALJs at a different state agency) during its November 14, 2019 open meeting but delayed final determination for further consideration. The PUCT again discussed the Houston Electric rate case at its December 13, 2019 open meeting and concluded that the PUCT would consider settlement a reasonable approach to resolving the rate case and noted that Houston Electric had indicated settlement negotiations were already underway. Houston Electric updated the PUCT at its January 16, 2020 open meeting regarding the status of settlement discussions, indicating that the parties were working on a settlement and anticipated a final settlement in the near future. On January 23, 2020, Houston Electric filed a Stipulation and Settlement Agreement with the PUCT that provides for the following, among other things:

• an overall revenue requirement increase of approximately $13 million;

• an ROE of 9.4%;

• a capital structure of 57.5% debt/42.5% equity;

• a refund of unprotected EDIT of $105 million plus carrying costs over approximately 30-36 months; and

• recovery of all retail transmission related costs through the TCRF.

Also, Houston Electric is not required to make a one-time refund of capital recovery from its TCOS and DCRF mechanisms. Future TCOS filings will take into account both ADFIT and EDIT until the final order from Houston Electric’s next base rate proceeding. No rate base items are required to be written off; however, approximately $12 million in rate case expenses were written off in 2019. A base rate application must be filed for Houston Electric no later than four years from the date of the PUCT’s final order in the proceeding. Additionally, Houston Electric will not file a DCRF in 2020, nor will a subsequent separate proceeding with the PUCT be instituted regarding EDIT on Houston Electric’s securitized assets.

Furthermore, under the terms of the Stipulation and Settlement Agreement, Houston Electric agreed to adopt certain ring-fencing measures to increase its financial separateness from CenterPoint Energy, which include the following:

• Houston Electric’s credit agreements and indentures shall not contain cross-default provisions by which a default by CenterPoint Energy or its other affiliates would cause a default at Houston Electric;

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• The financial covenant in Houston Electric’s credit agreement shall not be related to any entity other than Houston Electric. Houston Electric shall not include in its debt or credit agreements any financial covenants or rating agency triggers related to any entity other than Houston Electric;

• Houston Electric shall not pledge its assets in respect of or guarantee any debt or obligation of any of its affiliates. Houston Electric shall not pledge, mortgage, hypothecate, or grant a lien upon the property of Houston Electric except pursuant to an exception in effect in Houston Electric’s current credit agreement, such as Houston Electric’s first mortgage and general mortgage;

• Houston Electric shall maintain its own stand-alone credit facility, and Houston Electric shall not share its credit facility with any regulated or unregulated affiliate;

• Houston Electric shall maintain ratings with all three major credit ratings agencies;

• Houston Electric shall maintain a stand-alone credit rating;

• Houston Electric’s first mortgage bonds and general mortgage bonds shall be secured only with assets of Houston Electric;

• No Houston Electric assets may be used to secure the debt of CenterPoint Energy or its other affiliates;

• Houston Electric shall not hold out its credit as being available to pay the debt of any affiliates (provided that, for the avoidance of doubt, Houston Electric is not considered to be holding its credit out to pay the debt of affiliates, or in breach of any other ring-fencing measure, with respect to the $68 million of Houston Electric general mortgage bonds that currently serve as collateral for certain outstanding CenterPoint Energy pollution control bonds);

• Without prior approval of the PUCT, neither CenterPoint Energy nor any affiliate of CenterPoint Energy (excluding Houston Electric) may incur, guarantee, or pledge assets in respect of any incremental new debt that is dependent on: (1) the revenues of Houston Electric in more than a proportionate degree than the other revenues of CenterPoint Energy; or (2) the equity of Houston Electric;

• Houston Electric shall not transfer any material assets or facilities to any affiliates, other than a transfer that is on an arm’s length basis consistent with the PUCT’s affiliate standards applicable to Houston Electric;

• Except for its participation in an affiliate money pool, Houston Electric shall not commingle its assets with those of other CenterPoint Energy affiliates;

• Except for its participation in an affiliate money pool, Houston Electric shall not lend money to or borrow money from CenterPoint Energy; and

• Houston Electric shall notify the PUCT if its issuer credit rating or corporate credit rating as rated by any of the three major rating agencies falls below investment grade.

The PUCT approved the Stipulation and Settlement Agreement at its February 14, 2020 open meeting. A final order from the PUCT is currently expected during the first quarter of 2020; however, motions for rehearing, if granted, could result in the order being issued after the first quarter of 2020. The rates are expected to be implemented 45 days after the final order is issued.

CenterPoint Energy and Houston Electric record pre-tax expense for (i) probable disallowances of capital investments and (ii) customer refund obligations and costs deferred in regulatory assets when the amounts are no longer considered probable of recovery.

Brazos Valley Connection Project (CenterPoint Energy and Houston Electric)

Houston Electric completed construction on and energized the Brazos Valley Connection in March 2018, ahead of the original June 1, 2018 energization date. The final capital costs of the project reported to the PUCT in December 2018 were $281 million, which was within the estimated range of approximately $270-$310 million in the PUCT’s original order. In a filing with the PUCT in September 2018, Houston Electric applied for interim recovery of project costs incurred through July 31, 2018, which were not previously included in rates. Houston Electric received approval for interim recovery in November 2018. Final approval of the project costs occurred in Houston Electric’s base rate case discussed above.

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

In April 2017, Houston Electric submitted a proposal to ERCOT requesting its endorsement of the Bailey to Jones Creek Project. On December 12, 2017, Houston Electric received approval from ERCOT. In September 2018, Houston Electric filed a certificate of convenience and necessity application with the PUCT that included capital cost estimates for the project that ranged from approximately $482-$695 million, which were higher than the initial cost estimates. The revised project cost estimates include additional costs associated with the routing of the line to mitigate environmental and other land use impacts and structure design to address soil and coastal wind conditions. The actual capital costs of the project will depend on those factors as well as other factors, including land acquisition costs, construction costs and the ultimate route approved by the PUCT. On the request of the PUCT, ERCOT intervened in the proceeding and performed a re-evaluation of the cost-effectiveness of the proposed project. Based on that re-evaluation, ERCOT reaffirmed the recommended transmission option for the project. An unopposed settlement agreement was filed on August 15, 2019, under which Houston Electric would construct the project at an estimated cost of approximately $483 million. The PUCT issued its final approval of the certificate of convenience and necessity application on November 21, 2019. Houston Electric has commenced pre-construction activities on the project, and anticipates beginning construction in early 2021 and energizing the line in early 2022.

Indiana Electric Generation Project (CenterPoint Energy)

Indiana Electric must make substantial investments in its generation resources in the near term to comply with environmental regulations. On February 20, 2018, Indiana Electric filed a petition seeking authorization from the IURC to construct a new 700-850 MW natural gas combined cycle generating facility to replace the baseload capacity of its existing generation fleet at an approximate cost of $900 million, which includes the cost of a new natural gas pipeline to serve the plant.

As a part of this same proceeding, Indiana Electric also sought recovery under Indiana Senate Bill 251 of costs to be incurred for environmental investments to be made at its F.B. Culley generating plant to comply with ELG and CCR rules. The F.B. Culley investments, estimated to be approximately $95 million, began in 2019 and will allow the F.B. Culley Unit 3 generating facility to comply with environmental requirements and continue to provide generating capacity to Indiana Electric’s customers. Under Indiana Senate Bill 251, Indiana Electric sought authority to recover 80% of the approved costs, including a return, using a tracking mechanism, with the remaining 20% of the costs deferred for recovery in Indiana Electric’s next base rate proceeding.

On April 24, 2019, the IURC issued an order approving the environmental investments proposed for the F.B. Culley generating facility, along with recovery of prior pollution control investments made in 2014. The order denied the proposed gas combined cycle generating facility. Indiana Electric is conducting a new IRP, expected to be completed in mid-2020, to identify an appropriate investment of capital in its generation fleet to satisfy the needs of its customers and comply with environmental regulations.

Indiana Electric Solar Project (CenterPoint Energy)

On February 20, 2018, Indiana Electric announced it was finalizing details to install an additional 50 MW of universal solar energy, consistent with its IRP, with a petition seeking authority to recover costs associated with the project pursuant to Indiana Senate Bill 29. Indiana Electric filed a settlement agreement with the intervening parties whereby the energy produced by the solar farm would be set at a fixed market rate over the life of the investment and recovered within Indiana Electric’s CECA mechanism. On March 20, 2019, the IURC approved the settlement. Indiana Electric reached an agreement with the other settling parties to amend the settlement agreement to ensure the project would not cause negative tax consequences. Indiana Electric filed the amended settlement agreement with the IURC on September 16, 2019, and on January 29, 2020 the IURC approved the amended settlement agreement.

Indiana Electric A.B. Brown Ash Pond Remediation (CenterPoint Energy)

On August 14, 2019, Indiana Electric filed a petition with the IURC, seeking approval, as a federally mandated project, for the recovery of costs associated with the clean closure of the A.B. Brown ash pond pursuant to Indiana Senate Bill 251. This project, expected to last approximately 14 years, would result in the full excavation and recycling of the ponded ash through agreements with a beneficial reuse entity, totaling approximately $160 million. Under Indiana Senate Bill 251, Indiana Electric seeks authority to recover via a tracking mechanism 80% of the approved costs, with a return on eligible capital investments needed to allow for the extraction of the ponded ash, with the remaining 20% of the costs deferred for recovery in Indiana Electric’s next base rate proceeding. On December 19, 2019 and subsequently on January 10, 2020, Indiana Electric filed a settlement agreement with the intervening parties whereby the costs would be recovered as requested, with an additional commitment by Indiana Electric to offset the federally mandated costs by at least $25 million, representing a combination of total cash proceeds received from the

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ash reuser and total insurance proceeds to be received from Indiana Electric’s insurers in confidential settlement agreements in the pending Complaint for Damages and Declaratory Relief filing. The settlement agreement is pending before the IURC, with an order expected in the first half of 2020. If approved, Indiana Electric would expect recovery of the approved costs to commence in 2021.

Rate Change Applications

The Registrants are routinely involved in rate change applications before state regulatory authorities. Those applications include general rate cases, where the entire cost of service of the utility is assessed and reset. In addition, Houston Electric is periodically involved in proceedings to adjust its capital tracking mechanisms (TCOS and DCRF) and annually files to adjust its EECRF. CERC is periodically involved in proceedings to adjust its capital tracking mechanisms in Texas (GRIP), its cost of service adjustments in Arkansas, Louisiana, Mississippi and Oklahoma (FRP, RSP, RRA and PBRC, respectively), its decoupling mechanism in Minnesota, and its energy efficiency cost trackers in Arkansas, Minnesota, Mississippi and Oklahoma (EECR, CIP, EECR and EECR, respectively). CenterPoint Energy is periodically involved in proceedings to adjust its capital tracking mechanisms in Indiana (CSIA for gas and TDSIC for Electric) and Ohio (DRR), its decoupling mechanism in Indiana (SRC for gas), and its energy efficiency cost trackers in Indiana (EEFC for gas and DSMA for electric) and Ohio (EEFR).

The table below reflects significant applications pending or completed during 2019 and to date in 2020 for the Registrants.

Mechanism	Annual Increase (Decrease) (1) (in millions)	Filing  Date	Effective Date	Approval Date	Additional Information
CenterPoint Energy and Houston Electric (PUCT)
Rate Case (1)	$155	April 2019	TBD	TBD	See discussion above under Houston Electric Base Rate Case.
EECRF	7	May 2019	March 2020	October 2019	The PUCT issued a final order in October 2019 approving recovery of 2020 EECRF of $35 million, including a $7 million performance bonus.
CenterPoint Energy and CERC - Beaumont/East Texas, South Texas, Houston and Texas Coast (Railroad Commission)
GRIP	20	March 2019	July 2019	June 2019	Based on net change in invested capital of $123 million.
Rate Case (1)	7	November 2019	TBD	TBD	Reflects a proposed 10.40% ROE on a 58% equity ratio. Additionally, the proposal includes a refund for an Unprotected EDIT Rider amortized over 3 years of which $2.2 million is refunded in Year 1 and a request of $0.2 million for a Hurricane Surcharge, resulting from Hurricane Harvey, over 1 year.
CenterPoint Energy and CERC - Houston and Texas Coast (Railroad Commission)
Administrative 104.111	N/A	August 2019	January 2020	October 2019	On August 1, 2019, and subsequent supplemental filings in August and October 2019, Houston and Texas Coast proposed a rider to refund over three years to its Houston and Texas Coast customers combined, approximately $18 million of unprotected EDIT related to the TCJA.
CenterPoint Energy and CERC - South Texas (Railroad Commission)
Administrative 104.111	N/A	November 2019	March 2020	January 2020	On November 14, 2019, South Texas proposed to refund protected EDIT, amortized over ARAM. The estimated refund for the first year is $0.6 million.
CenterPoint Energy and CERC - Arkansas (APSC)
FRP	7	April 2019	October 2019	August 2019	Based on ROE of 9.5% approved in the last rate case. On August 23, 2019, the APSC approved a unanimous comprehensive settlement that results in an FRP revenue increase of $7 million and includes additional non-monetary items.
CenterPoint Energy and CERC - Louisiana (LPSC)
RSP	3	September 2019	December 2019	December 2019	Based on ROE of 9.95%.
CenterPoint Energy and CERC - Minnesota (MPUC)
CIP Financial Incentive	11	May 2019	October 2019	September 2019	CIP Financial Incentive based on 2018 activity.
Decoupling	N/A	September 2019	September 2019	January 2020	Represents over-recovery of $21 million recorded for and during the period July 1, 2018 through June 30, 2019, partially offset by over-refund of $2 million related to the period July 1, 2017 through June 30, 2018.
Rate Case (1)	62	October 2019	TBD	TBD	Reflects a proposed 10.15% ROE on a 51.39% equity ratio. Interim rates were approved and reflect an annual increase of $53 million, effective January 1, 2020.
CenterPoint Energy and CERC - Mississippi (MPSC)
RRA	2	May 2019	November 2019	November 2019	Based on ROE of 9.26%.

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Mechanism	Annual Increase (Decrease) (1) (in millions)	Filing  Date	Effective Date	Approval Date	Additional Information
CenterPoint Energy and CERC - Oklahoma (OCC)
PBRC	2	March 2019	September 2019	August 2019	Based on ROE of 10%. On July 26, 2019, the ALJ recommended that the OCC approve an increase of $2 million. On August 29, 2019, the OCC approved the ALJ-recommended revenue increase of $2 million.
CenterPoint Energy - Indiana South - Gas (IURC)
CSIA	3	October 2018	January 2019	January 2019	Requested an increase of $16 million to rate base, which reflects a $3 million annual increase in current revenues. 80% of revenue requirement is included in requested rate increase and 20% is deferred until next rate case. The mechanism also includes refunds associated with the TCJA, resulting in a change of $(1) million, and a change in the total (over)/under-recovery variance of $(3) million annually.
CSIA	5	April 2019	July 2019	July 2019	Requested an increase of $22 million to rate base, which reflects a $5 million annual increase in current revenues. 80% of revenue requirement is included in requested rate increase and 20% is deferred until the next rate case. The mechanism also includes refunds associated with the TCJA, resulting in no change to the previous credit provided, and a change in the total (over)/under-recovery variance of $3 million annually.
CSIA	3	October 2019	January 2020	January 2020	Requested an increase of $18 million to rate base, which reflects a $3 million annual increase in current revenues. 80% of revenue requirement is included in requested rate increase and 20% is deferred until the next rate case. The mechanism also includes refunds associated with the TCJA, resulting in no change to the previous credit provided, and a change in the total (over)/under-recovery variance of $(0.2) million annually.
CenterPoint Energy - Indiana North - Gas (IURC)
CSIA	3	October 2018	January 2019	January 2019	Requested an increase of $54 million to rate base, which reflects a $3 million annual increase in current revenues. 80% of revenue requirement is included in requested rate increase and 20% is deferred until next rate case. The mechanism also includes refunds associated with the TCJA, resulting in a change of $(11) million, and a change in the total (over)/under-recovery variance of $(19) million annually.
CSIA	12	April 2019	July 2019	July 2019	Requested an increase of $58 million to rate base, which reflects a $12 million annual increase in current revenues. 80% of revenue requirement is included in requested rate increase and 20% is deferred until next rate case. The mechanism also includes refunds associated with the TCJA, resulting in no change to the previous credit provided, and a change in the total (over)/under-recovery variance of $14 million annually.
CSIA	4	October 2019	January 2020	January 2020	Requested an increase of $29 million to rate base, which reflects a $4 million annual increase in current revenues. 80% of revenue requirement is included in requested rate increase and 20% is deferred until next rate case. The mechanism also includes refunds associated with the TCJA, resulting in no change to the previous credit provided, and a change in the total (over)/under-recovery variance of $(7) million annually.
CenterPoint Energy - Ohio (PUCO)
DRR	11	May 2019	September 2019	August 2019	Requested an increase of $78 million to rate base for investments made in 2018, which reflects a $11 million annual increase in current revenues. A change in (over)/under-recovery variance of $(3) million annually is also included in rates. All pre-2018 investments are included in rate case request.
Rate Case	23	March 2018	September 2019	August 2019	Settlement agreement approved by PUCO Order that provides for a $23 million annual increase in current revenues. Order based upon $622 million of total rate base, a 7.48% overall rate of return, and extension of conservation and DRR programs.
TSCR (1)	N/A	January 2019	TBD	TBD	Application to flow back to customers certain benefits from the TCJA. Initial impact reflects credits for 2018 of $(10) million and 2019 of $(8) million, with mechanism to begin subsequent to new base rates. Order is expected in early 2020.

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Mechanism	Annual Increase (Decrease) (1) (in millions)	Filing  Date	Effective Date	Approval Date	Additional Information
CenterPoint Energy - Indiana Electric (IURC)
TDSIC	3	February 2019	May 2019	May 2019	Requested an increase of $24 million to rate base, which reflects a $3 million annual increase in current revenues. 80% of revenue requirement is included in requested rate increase and 20% is deferred until next rate case. The mechanism also includes refunds associated with the TCJA, resulting in a change of $5 million, and a change in the total (over)/under-recovery variance of $5 million annually.
TDSIC	4	August 2019	November 2019	November 2019	Requested an increase of $35 million to rate base, which reflects a $4 million annual increase in current revenues. 80% of revenue requirement is included in requested rate increase and 20% is deferred until next rate case. The mechanism also includes a change in (over)/under-recovery variance of $4 million annually.
TDSIC (1)	4	February 2020	May  2020	TBD	Requested an increase of $34 million to rate base, which reflects a $4 million annual increase in current revenues. 80% of revenue requirement is included in requested rate increase and 20% is deferred until next rate case. The mechanism also includes a change in (over)/under-recovery variance of $2 million annually.
ECA - MATS	13	February 2018	January 2019	April 2019	Requested an increase of $58 million to rate base, which reflects a $13 million annual increase in current revenues. 80% of revenue requirement is included in requested rate increase and 20% is deferred until next rate case. The mechanism includes recovery of prior accounting deferrals associated with investments (depreciation, carrying costs, operating expenses).
CECA	2	February 2019	June 2019	May 2019	Requested an increase of $13 million to rate base related to solar pilot investments, which reflects a $2 million annual increase in current revenues.
CECA (1)	0.1	February 2020	June  2020	TBD	Requested an increase of $0.1 million to rate base related to solar pilot investments, which reflects an immaterial change to current revenues. The mechanism also includes a change in (over)/under-recovery variance of $0.1 million annually. Additional solar investment to supply 50 MW of solar capacity is approved and will be included for recovery once completed in 2021.

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

Tax Reform

TCJA-related 2018 tax expense refunds are currently included in the Registrants’ existing rates and are therefore reducing the Registrants’ current annual revenue. The TCJA-related 2018 tax expense refunds for Houston Electric were completed in September 2019. However, in Houston Electric’s rate case filed in April 2019, and subsequently adjusted in errata filings in May and June 2019, pursuant to the Stipulation and Settlement Agreement, Houston Electric will return unprotected EDIT net regulatory liability balance to customers, through a separate rider and its wholesale transmission tariff over approximately three years. The balance of unprotected EDIT was $105 million as of December 31, 2018. In addition, Houston Electric’s TCJA-related protected EDIT balance as of December 31, 2018 is $563 million and must be returned to customers over ARAM.

CenterPoint Energy’s electric and natural gas utilities in Indiana and Ohio, which were acquired during the Merger, currently recover corporate income tax expense in approved rates charged to customers. The IURC and the PUCO both issued orders which initiated proceedings to investigate the impact of the TCJA on utility companies and customers within Indiana and Ohio, respectively. In addition, the IURC and PUCO have ordered each utility to establish regulatory liabilities to record all estimated impacts of tax reform starting January 1, 2018 until the date when rates are adjusted to capture these impacts. In Indiana, in response to Vectren’s pre-Merger filing for proposed changes to its rates and charges to consider the impact of the lower federal income tax rates, the IURC approved an initial reduction to current rates and charges, effective June 1, 2018, to capture the immediate impact of the lower corporate federal income tax rate. The refund of EDIT and regulatory liabilities commenced in November 2018 for Indiana electric customers and in January 2019 for Indiana gas customers. In Ohio, the initial rate reduction to current rates and charges became effective upon conclusion of its pending base rate case on August 28, 2019. In January 2019, an application was filed with PUCO in compliance with its October 2018 order requiring utilities to file for a request to adjust rates to reflect the impact of the TCJA, requesting authority to implement a rider to flow back to customers the tax benefits realized under the TCJA, including the refund of EDIT and regulatory liabilities. CenterPoint Energy expects this proceeding to be approved in 2020.

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ELG (CenterPoint Energy)

Under the Clean Water Act, the EPA sets technology-based guidelines for water discharges from new and existing electric generation facilities. In September 2015, the EPA finalized revisions to the existing steam electric ELG setting stringent technology-based water discharge limits for the electric power industry. The EPA focused this rulemaking on wastewater generated primarily by pollution control equipment necessitated by the comprehensive air regulations, specifically setting strict water discharge limits for arsenic, mercury and selenium for scrubber waste waters. The ELG will be implemented when existing water discharge permits for the plants are renewed. In the case of Indiana Electric’s water discharge permits, in 2017 the IDEM issued final renewals for the F.B. Culley and A.B. Brown power plants. IDEM agreed that units identified for retirement by December 2023 would not be required to install new treatment technology to meet ELG, and approved a 2020 compliance date for dry bottom ash and a 2023 compliance date for flue gas desulfurization wastewater treatment standards for the remaining coal-fired unit at F.B. Culley.

On April 13, 2017, as part of the U.S. President’s Administration’s regulatory reform initiative, which is focused on the number and nature of regulations, the EPA granted petitions to reconsider the ELG rule, and indicated it would stay the current implementation deadlines in the rule during the pendency of the reconsideration. On September 13, 2017, the EPA finalized a rule postponing certain interim compliance dates by two years, but did not postpone the final compliance deadline of December 31, 2023. In April 2018, the EPA published an effluent guidelines program plan that anticipated a December 2019 rule revising the effluent limitations and pre-treatment standards for existing sources in the 2015 rule. On April 12, 2019, the U.S. Court of Appeals for the Fifth Circuit vacated and remanded portions of the ELG rule that selected impoundment as the best available technology for legacy wastewater and leachate. It is not clear what revisions to the ELG rule the EPA will implement, or what effect those revisions may have. As Indiana Electric does not currently have short-term ELG implementation deadlines in its recently renewed wastewater discharge permits, it does not anticipate immediate impacts from the EPA’s two-year extension of preliminary implementation deadlines due to the longer compliance time frames granted by IDEM and will continue to work with IDEM to evaluate further implementation plans. On November 4, 2019, the EPA released a pre-publication copy of proposed revisions to the CCR and ELG rules. CenterPoint Energy will evaluate the proposals to determine potential impacts to current compliance plans for its A.B. Brown and F.B. Culley generating stations.

CPP and ACE Rule (CenterPoint Energy)

On August 3, 2015, the EPA released its CPP Rule, which required a 32% reduction in carbon emissions from 2005 levels. The final rule was published in the Federal Register on October 23, 2015, and that action was immediately followed by litigation ultimately resulting in the U.S. Supreme Court staying implementation of the rule. On August 31, 2018, the EPA published its proposed CPP replacement rule, the ACE Rule, which was finalized on July 8, 2019 and requires states to implement a program of energy efficiency improvement targets for individual coal-fired electric generating units. States have three years to develop state plans to implement the ACE rule, and CenterPoint Energy does not expect a state ACE rule to be finalized and approved by the EPA until 2024. CenterPoint Energy is currently unable to predict the effect of a state plan to implement the ACE rule but does not anticipate that such a plan would have a material effect.

Impact of Legislative Actions & Other Initiatives (CenterPoint Energy)

At this time, compliance costs and other effects associated with reductions in GHG emissions or obtaining renewable energy sources remain uncertain. While the requirements of a state ACE rule remain uncertain, Indiana Electric will continue to monitor regulatory activity regarding GHG emission standards that may affect its electric generating units.

FERC Revised Policy Statement (CenterPoint Energy)

The regulation of midstream energy infrastructure assets has a significant impact on Enable’s business. For example, Enable’s interstate natural gas transportation and storage assets are subject to regulation by the FERC under the NGA. In March 2018, the FERC announced a Revised Policy Statement stating that it would no longer allow pipelines organized as a master limited partnership to recover an income tax allowance in their cost-of-service rates. In July 2018, the FERC issued new regulations which required all FERC-regulated natural gas pipelines to make a one-time Form No. 501-G filing providing certain financial information. In October 2018, Enable Gas Transmission, LLC filed its Form No. 501-G and filed a statement that it intended to take no other action. On March 8, 2019, the FERC terminated the 501-G proceeding and required no other action. MRT did not file a FERC Form No. 501-G because it had filed a general rate case in June 2018. In July 2018, the FERC issued an order accepting MRT’s proposed rate increases subject to refund upon a final determination of MRT’s rates and ordering MRT to refile its rate case to reflect the elimination of an income tax allowance in its cost-of-service rates. On August 30, 2018, MRT submitted a supplemental filing to comply with the FERC’s order. MRT has appealed the FERC’s order to eliminate the income tax allowance in its cost-of-service rates. The FERC set MRT’s re-filed rate case for hearing. The procedural schedule has been suspended to afford MRT

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time to file a settlement. If a settlement is not filed or all of the participants do not agree to a settlement, then the proceeding may advance to hearing. On November 5, 2019, as supplemented on December 13, 2019, MRT filed an uncontested proposed settlement for its 2018 rate case. On October 30, 2019, MRT filed a second general rate case with the FERC pursuant to Section 4 of the NGA. The 2019 rate case was necessary because at the time of filing the 2019 rate case, the proposed settlement of the 2018 rate case was still being contested, requiring that new maximum rates be established for the non-settling parties reflecting the turnback of capacity. On November 5, 2019, MRT filed an uncontested proposed settlement for the 2019 rate case. Subsequently, MRT reached agreement with 100% of the parties participating in the MRT rate cases, and these rate case settlements are pending at the FERC. The FERC may accept or reject the proposed settlements in the 2018 and 2019 rate cases as to all of the parties, or may reject one or both of the settlements and set one or both of the rate cases for hearing.

Other Matters

Credit Facilities

The Registrants may draw on their respective revolving credit facilities from time to time to provide funds used for general corporate and limited liability company purposes, including to backstop CenterPoint Energy’s and CERC’s commercial paper programs. The facilities may also be utilized to obtain letters of credit. For further details related to the Registrants’ revolving credit facilities, please see Note 14 to the consolidated financial statements.

Based on the consolidated debt to capitalization covenant in the Registrants’ revolving credit facilities, the Registrants would have been permitted to utilize the full capacity of such revolving credit facilities, which aggregated approximately $5.1 billion as of December 31, 2019. As of February 19, 2020, the Registrants had the following revolving credit facilities and utilization of such facilities:

			Amount Utilized as of February 19, 2020
Registrant	Size of Facility		Loans		Letters of Credit		Commercial Paper		Weighted Average Interest Rate	Termination Date
	(in millions)
CenterPoint Energy	$	3,300	$	—	$	6	$	1,824	1.79%	March 3, 2022
CenterPoint Energy (1)	400		—		—		207		1.86%	July 14, 2022
CenterPoint Energy (2)	200		—		—		—		—	July 14, 2022
Houston Electric	300		—		—		—		—	March 3, 2022
CERC	900		—		1		205		1.73%	March 3, 2022
Total	$	5,100	$	—	$	7	$	2,236

(1) The credit facility was issued by VUHI and is guaranteed by SIGECO, Indiana Gas and VEDO.

(2) The credit facility was issued by VCC and is guaranteed by Vectren.

Borrowings under each of the revolving credit facilities are subject to customary terms and conditions. However, there is no requirement that the borrower makes representations prior to borrowing as to the absence of material adverse changes or litigation that could be expected to have a material adverse effect. Borrowings under each of the revolving credit facilities are subject to acceleration upon the occurrence of events of default that we consider customary. The revolving credit facilities also provide for customary fees, including commitment fees, administrative agent fees, fees in respect of letters of credit and other fees. In each of the revolving credit facilities, the spread to LIBOR and the commitment fees fluctuate based on the borrower’s credit rating. The borrowers are currently in compliance with the various business and financial covenants in the five revolving credit facilities.

Long-term Debt

For detailed information about the Registrants’ debt issuances in 2019, see Note 14 to the consolidated financial statements.

Securities Registered with the SEC

On January 31, 2017, the Registrants filed a joint shelf registration statement with the SEC, as amended on September 24, 2018, registering indeterminate principal amounts of Houston Electric’s general mortgage bonds, CERC Corp.’s senior debt securities

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and CenterPoint Energy’s senior debt securities and junior subordinated debt securities and an indeterminate number of shares of Common Stock, shares of preferred stock, depositary shares, as well as stock purchase contracts and equity units. The joint shelf registration statement expired on January 31, 2020. For information related to the Registrants’ debt and equity security issuances in 2019, see Notes 13 and 14 to the consolidated financial statements.

Temporary Investments

As of February 19, 2020, the Registrants had no temporary investments.

Money Pool

The Registrants participate in a money pool through which they and certain of their subsidiaries can borrow or invest on a short-term basis. Funding needs are aggregated and external borrowing or investing is based on the net cash position. The net funding requirements of the CenterPoint Energy money pool are expected to be met with borrowings under CenterPoint Energy’s revolving credit facility or the sale of CenterPoint Energy’s commercial paper. The net funding requirements of the CERC money pool are expected to be met with borrowings under CERC’s revolving credit facility or the sale of CERC’s commercial paper. The money pool may not provide sufficient funds to meet the Registrants’ cash needs.

The table below summarizes CenterPoint Energy money pool activity by Registrant as of February 19, 2020:

	Weighted Average Interest Rate	Houston Electric		CERC
		(in millions)
Money pool investments	1.81%	$	282	$	—

Impact on Liquidity of a Downgrade in Credit Ratings

The interest on borrowings under the Registrants’ credit facilities is based on their credit ratings. The interest on borrowings under the credit facilities is based on each respective borrower’s credit ratings. On October 25, 2019, Moody’s downgraded VUHI’s and Indiana Gas’ senior unsecured debt rating to A3 from A2 and SIGECO’s senior secured debt rating to A1 from Aa3. The outlooks of VUHI, Indiana Gas and SIGECO were revised to stable from negative. On November 18, 2019, Moody’s withdrew the ratings of Indiana Gas. On November 21, 2019, Moody’s placed the A3 senior unsecured rating, A3 Issuers rating, and A1 senior secured rating of Houston Electric on review for downgrade. On February 19, 2020, Fitch downgraded Houston Electric’s senior secured debt to A from A+ with a negative outlook and affirmed CenterPoint Energy’s BBB rating with a negative outlook. As of February 19, 2020, Moody’s, S&P and Fitch had assigned the following credit ratings to senior debt of the Registrants:

		Moody’s		S&P		Fitch
Registrant	Borrower/Instrument	Rating	Outlook (1)	Rating	Outlook (2)	Rating	Outlook (3)
CenterPoint Energy	CenterPoint Energy Senior Unsecured Debt	Baa2	Stable	BBB	Stable	BBB	Negative
CenterPoint Energy	Vectren Corp. Issuer Rating	n/a	n/a	BBB+	Stable	n/a	n/a
CenterPoint Energy	VUHI Senior Unsecured Debt	A3	Stable	BBB+	Stable	n/a	n/a
CenterPoint Energy	Indiana Gas Senior Unsecured Debt	n/a	n/a	BBB+	Stable	n/a	n/a
CenterPoint Energy	SIGECO Senior Secured Debt	A1	Stable	A	Stable	n/a	n/a
Houston Electric	Houston Electric Senior Secured Debt	A1	Under Review	A	Stable	A	Negative
CERC	CERC Corp. Senior Unsecured Debt	Baa1	Positive	BBB+	Stable	BBB+	Stable

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

(2) An S&P outlook assesses the potential direction of a long-term credit rating over the intermediate to longer term.

(3) A Fitch rating outlook indicates the direction a rating is likely to move over a one- to two-year period.

The Registrants cannot assure that the ratings set forth above will remain in effect for any given period of time or that one or more of these ratings will not be lowered or withdrawn entirely by a rating agency. The Registrants note that these credit ratings

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are included for informational purposes and are not recommendations to buy, sell or hold the Registrants’ securities and may be revised or withdrawn at any time by the rating agency. Each rating should be evaluated independently of any other rating. Any future reduction or withdrawal of one or more of the Registrants’ credit ratings could have a material adverse impact on the Registrants’ ability to obtain short- and long-term financing, the cost of such financings and the execution of the Registrants’ commercial strategies.

A decline in credit ratings could increase borrowing costs under the Registrants’ revolving credit facilities. If the Registrants’ credit ratings had been downgraded one notch by S&P and Moody’s from the ratings that existed as of December 31, 2019, the impact on the borrowing costs under the five revolving credit facilities would have been immaterial. A decline in credit ratings would also increase the interest rate on long-term debt to be issued in the capital markets and could negatively impact the Registrants’ ability to complete capital market transactions and to access the commercial paper market. Additionally, a decline in credit ratings could increase cash collateral requirements and reduce earnings of CenterPoint Energy’s and CERC’s Natural Gas Distribution and Energy Services reportable segments.

CES, a wholly-owned subsidiary of CERC operating in the Energy Services reportable segment, provides natural gas sales and services primarily to commercial and industrial customers and electric and natural gas utilities throughout the United States. To economically hedge its exposure to natural gas prices, CES uses derivatives with provisions standard for the industry, including those pertaining to credit thresholds. Typically, the credit threshold negotiated with each counterparty defines the amount of unsecured credit that such counterparty will extend to CES. To the extent that the credit exposure that a counterparty has to CES at a particular time does not exceed that credit threshold, CES is not obligated to provide collateral. Mark-to-market exposure in excess of the credit threshold is routinely collateralized by CES. Similarly, mark-to-market exposure offsetting and exceeding the credit threshold may cause the counterparty to provide collateral to CES. As of December 31, 2019, the amount posted by CES as collateral aggregated approximately $92 million. Should the credit ratings of CERC Corp. (as the credit support provider for CES) fall below certain levels, CES would be required to provide additional collateral up to the amount of its previously unsecured credit limit. CenterPoint Energy and CERC estimate that as of December 31, 2019, unsecured credit limits extended to CES by counterparties aggregated $467 million, and none of such amount was utilized.

Pipeline tariffs and contracts typically provide that if the credit ratings of a shipper or the shipper’s guarantor drop below a threshold level, which is generally investment grade ratings from both Moody’s and S&P, cash or other collateral may be demanded from the shipper in an amount equal to the sum of three months’ charges for pipeline services plus the unrecouped cost of any lateral built for such shipper. If the credit ratings of CERC Corp. decline below the applicable threshold levels, CERC might need to provide cash or other collateral of as much as $181 million as of December 31, 2019. The amount of collateral will depend on seasonal variations in transportation levels.

ZENS and Securities Related to ZENS (CenterPoint Energy)

If CenterPoint Energy’s creditworthiness were to drop such that ZENS holders thought its liquidity was adversely affected or the market for the ZENS were to become illiquid, some ZENS holders might decide to exchange their ZENS for cash. Funds for the payment of cash upon exchange could be obtained from the sale of the shares of ZENS-Related Securities that CenterPoint Energy owns or from other sources. CenterPoint Energy owns shares of ZENS-Related Securities equal to approximately 100% of the reference shares used to calculate its obligation to the holders of the ZENS. ZENS exchanges result in a cash outflow because tax deferrals related to the ZENS and shares of ZENS-Related Securities would typically cease when ZENS are exchanged or otherwise retired and shares of ZENS-Related Securities are sold. The ultimate tax liability related to the ZENS continues to increase by the amount of the tax benefit realized each year, and there could be a significant cash outflow when the taxes are paid as a result of the retirement or exchange of the ZENS. If all ZENS had been exchanged for cash on December 31, 2019, deferred taxes of approximately $429 million would have been payable in 2019. If all the ZENS-Related Securities had been sold on December 31, 2019, capital gains taxes of approximately $149 million would have been payable in 2019. For additional information about ZENS, see Note 12 to the consolidated financial statements.

Cross Defaults

Under each of CenterPoint Energy’s, Houston Electric’s and CERC’s respective revolving credit facilities, as well as under CenterPoint Energy’s term loan agreement, a payment default on, or a non-payment default that permits acceleration of, any indebtedness for borrowed money and certain other specified types of obligations (including guarantees) exceeding $125 million by the borrower or any of their respective significant subsidiaries will cause a default under such borrower’s respective credit facility or term loan agreement. A default by CenterPoint Energy would not trigger a default under its subsidiaries’ debt instruments or revolving credit facilities.

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Under each of VUHI’s and VCC’s respective revolving credit facilities and term loan agreements, a payment default on, or a non-payment default that permits acceleration of, any indebtedness for borrowed money and certain other specified types of obligations (including guarantees) exceeding $50 million by the borrower, any of their respective subsidiaries or any of the respective guarantors of a credit facility or term loan agreement will cause a default under such borrower’s respective credit facility or term loan agreement.

Possible Acquisitions, Divestitures and Joint Ventures

From time to time, the Registrants consider the acquisition or the disposition of assets or businesses or possible joint ventures, strategic initiatives or other joint ownership arrangements with respect to assets or businesses. Any determination to take action in this regard will be based on market conditions and opportunities existing at the time, and accordingly, the timing, size or success of any efforts and the associated potential capital commitments are unpredictable. The Registrants may seek to fund all or part of any such efforts with proceeds from debt and/or equity issuances. Debt or equity financing may not, however, be available to the Registrants at that time due to a variety of events, including, among others, maintenance of our credit ratings, industry conditions, general economic conditions, market conditions and market perceptions.

CenterPoint Energy previously disclosed that it may reduce its ownership in Enable over time through sales in the public equity markets, or otherwise, of the Enable common units it holds, subject to market conditions. CenterPoint Energy has no intention to reduce its ownership of Enable common units and currently plans to hold such Enable common units and to utilize any cash distributions received on such Enable common units to finance a portion of CenterPoint Energy’s capital expenditure program. CenterPoint Energy may consider or alter its plans or proposals in respect of any such plans in the future.

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 is expected to close in the second quarter of 2020. For further information, see Notes 6 and 23 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. The transaction is expected to close in the second quarter of 2020.For further information, see Notes 6 and 23 to the consolidated financial statements.

Enable Midstream Partners (CenterPoint Energy and CERC)

In September 2018, CERC completed the Internal Spin, after which CERC’s equity investment in Enable met the criteria for discontinued operations classification. As a result, the operations have been classified as Income from discontinued operations, net of tax, in CERC’s Statements of Consolidated Income for the periods presented. For further information, see Note 11 to the consolidated financial statements.

CenterPoint Energy receives quarterly cash distributions from Enable on its common units and Enable Series A Preferred Units. A reduction in the cash distributions CenterPoint Energy receives from Enable could significantly impact CenterPoint Energy’s liquidity. For additional information about cash distributions from Enable, see Notes 11 and 23 to the consolidated financial statements.

Hedging of Interest Expense for Future Debt Issuances

From time to time, the Registrants may enter into interest rate agreements to hedge, in part, volatility in the U.S. treasury rates by reducing variability in cash flows related to interest payments. For further information, see Note 9(a) to the consolidated financial statements.

Weather Hedge (CenterPoint Energy and CERC)

CenterPoint Energy and CERC have historically entered into partial weather hedges for certain NGD jurisdictions and electric operations’ Texas service territory to mitigate the impact of fluctuations from normal weather. CenterPoint Energy and CERC remain exposed to some weather risk as a result of the partial hedges. For more information about weather hedges, see Note 9(a) to the consolidated financial statements.

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

Houston Electric’s receivables from the distribution of electricity are collected from REPs that supply the electricity Houston Electric distributes to their customers. Before conducting business, a REP must register with the PUCT and must meet certain financial qualifications. Nevertheless, adverse economic conditions, structural problems in the market served by ERCOT or financial difficulties of one or more REPs could impair the ability of these REPs to pay for Houston Electric’s services or could cause them to delay such payments. Houston Electric depends on these REPs to remit payments on a timely basis, and any delay or default in payment by REPs could adversely affect Houston Electric’s cash flows. In the event of a REP’s default, Houston Electric’s tariff provides a number of remedies, including the option for Houston Electric to request that the PUCT suspend or revoke the certification of the REP. Applicable regulatory provisions require that customers be shifted to another REP or a provider of last resort if a REP cannot make timely payments. However, Houston Electric remains at risk for payments related to services provided prior to the shift to the replacement REP or the provider of last resort. If a REP were unable to meet its obligations, it could consider, among various options, restructuring under the bankruptcy laws, in which event such REP might seek to avoid honoring its obligations and claims might be made against Houston Electric involving payments it had received from such REP. If a REP were to file for bankruptcy, Houston Electric may not be successful in recovering accrued receivables owed by such REP that are unpaid as of the date the REP filed for bankruptcy. However, PUCT regulations authorize utilities, such as Houston Electric, to defer bad debts resulting from defaults by REPs for recovery in future rate cases, subject to a review of reasonableness and necessity.

Other Factors that Could Affect Cash Requirements

In addition to the above factors, the Registrants’ liquidity and capital resources could be affected by:

• cash collateral requirements that could exist in connection with certain contracts, including weather hedging arrangements, and natural gas purchases, natural gas price and natural gas storage activities of CenterPoint Energy’s and CERC’s Natural Gas Distribution and Energy Services reportable segments; 

• acceleration of payment dates on certain gas supply contracts, under certain circumstances, as a result of increased natural gas prices and concentration of natural gas suppliers (CenterPoint Energy and CERC); 

• increased costs related to the acquisition of natural gas (CenterPoint Energy and CERC); 

• increases in interest expense in connection with debt refinancings and borrowings under credit facilities or term loans; 

• various legislative or regulatory actions; 

• incremental collateral, if any, that may be required due to regulation of derivatives (CenterPoint Energy and CERC); 

• the ability of REPs, including REP affiliates of NRG and Vistra Energy Corp., formerly known as TCEH Corp., to satisfy their obligations to CenterPoint Energy and Houston Electric;

• slower customer payments and increased write-offs of receivables due to higher natural gas prices or changing economic conditions (CenterPoint Energy and CERC); 

• the satisfaction of any obligations pursuant to guarantees;

• the outcome of litigation; 

• contributions to pension and postretirement benefit plans; 

• restoration costs and revenue losses resulting from future natural disasters such as hurricanes and the timing of recovery of such restoration costs; and

• various other risks identified in “Risk Factors” in Item 1A of Part I of this report.

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

Houston Electric has contractually agreed that it will not issue additional first mortgage bonds, subject to certain exceptions. For information about the total debt to capitalization financial covenants in the Registrants’ and certain of CenterPoint Energy’s subsidiaries’ revolving credit facilities, see Note 14 to the consolidated financial statements.

CRITICAL ACCOUNTING POLICIES

A critical accounting policy is one that is both important to the presentation of the Registrants’ financial condition and results of operations and requires management to make difficult, subjective or complex accounting estimates. An accounting estimate is an approximation made by management of a financial statement element, item or account in the financial statements. Accounting estimates in the Registrants’ historical consolidated financial statements measure the effects of past business transactions or events, or the present status of an asset or liability. The accounting estimates described below require the Registrants to make assumptions about matters that are highly uncertain at the time the estimate is made. Additionally, different estimates that the Registrants could have used or changes in an accounting estimate that are reasonably likely to occur could have a material impact on the presentation of their financial condition, results of operations or cash flows. The circumstances that make these judgments difficult, subjective and/or complex have to do with the need to make estimates about the effect of matters that are inherently uncertain. Estimates and assumptions about future events and their effects cannot be predicted with certainty. The Registrants base their estimates on historical experience and on various other assumptions that they believe to be reasonable under the circumstances, the results of which form the basis for making judgments. These estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as the Registrants’ operating environment changes. The Registrants’ significant accounting policies are discussed in Note 2 to the consolidated financial statements. The Registrants believe the following accounting policies involve the application of critical accounting estimates. Accordingly, these accounting estimates have been reviewed and discussed with the Audit Committee of CenterPoint Energy’s Board of Directors.

Accounting for Rate Regulation

Accounting guidance for regulated operations provides that rate-regulated entities account for and report assets and liabilities consistent with the recovery of those incurred costs in rates if the rates established are designed to recover the costs of providing the regulated service and if the competitive environment makes it probable that such rates can be charged and collected. CenterPoint Energy’s and Houston Electric’s Electric T&D reportable segment, CenterPoint Energy’s Indiana Electric Integrated reportable segment, and CenterPoint Energy’s and CERC’s Natural Gas Distribution reportable segments apply this accounting guidance. Certain expenses and revenues subject to utility regulation or rate determination normally reflected in income are deferred on the balance sheet as regulatory assets or liabilities and are recognized in income as the related amounts are included in service rates and recovered from or refunded to customers. Regulatory assets and liabilities are recorded when it is probable that these items will be recovered or reflected in future rates. Determining probability requires significant judgment on the part of management and includes, but is not limited to, consideration of testimony presented in regulatory hearings, proposed regulatory decisions, final regulatory orders and the strength or status of applications for rehearing or state court appeals. If events were to occur that would make the recovery of these assets and liabilities no longer probable, the Registrants would be required to write off or write down these regulatory assets and liabilities. For further detail on the Registrants’ regulatory assets and liabilities, see Note 7 to the consolidated financial statements.

Acquisition Accounting

The Registrants evaluate acquisitions to determine when a set of acquired activities and assets represent a business. When control of a business is obtained, the Registrants apply the acquisition method of accounting and record the assets acquired, liabilities assumed and any non-controlling interest obtained based on fair value at the acquisition date.

The fair values of tangible and intangible assets and liabilities subject to rate-setting provisions and earning a regulated return generally approximate their carrying values. The fair value of assets acquired and liabilities assumed that are not subject to the rate-setting provisions, including identifiable intangibles, are determined using the income and market approach, which estimation methods may require the use of significant judgment and unobservable inputs, including projected timing and amount of future cash flows and discount rates reflecting risk inherent in the future market prices. Any excess of the purchase price over the fair value amounts assigned to assets and liabilities is recorded as goodwill. The results of operations of the acquired business are included in the Registrants’ respective Statements of Consolidated Income beginning on the date of the acquisition.

On the Merger Date, pursuant to the Merger Agreement, CenterPoint Energy consummated the Merger and acquired Vectren for approximately $6 billion in cash. The Merger is being accounted for in accordance with ASC 805, Business Combinations,

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with CenterPoint Energy as the accounting acquirer of Vectren. Identifiable assets acquired and liabilities assumed have been recorded at their estimated fair values on the Merger Date.

Vectren’s regulated operations, comprised of electric generation and electric and natural gas delivery services, are subject to the rate-setting authority of the FERC, the IURC and the PUCO, and are accounted for pursuant to U.S. generally accepted accounting principles for regulated operations. The rate-setting and cost-recovery provisions currently in place for Vectren’s regulated operations provide revenues designed to recover the cost of providing utility service and a return on and recovery of investment in rate base assets and liabilities. Thus, the fair values of Vectren’s tangible and intangible assets and liabilities subject to these rate-setting provisions approximate their carrying values. Accordingly, neither the assets nor liabilities acquired reflect any adjustments related to these amounts. The fair value of regulatory assets not earning a return have been determined using the income approach and include the use of significant judgment and unobservable inputs.

The fair value of Vectren’s assets acquired and liabilities assumed that are not subject to the rate-setting provisions, including identifiable intangibles, and the allocation of fair value to reporting units on the Merger Date was determined under the income approach using the multi-period excess earnings method, which is a specific discounted cash flow income approach, and for the measurement of certain assets and liabilities, the market approach was utilized. 

Fair value measurements require significant judgment and unobservable inputs, including (i) projected timing and amount of future cash flows, which factor in planned growth initiatives, (ii) the regulatory environment, as applicable, and (iii) discount rates reflecting risk inherent in the future market prices. Determining the discount rates for the non-rate regulated businesses required the estimation of the appropriate company specific risk premiums for those non-rate regulated businesses based on evaluation of industry and entity-specific risks, which included expectations about future market or economic conditions existing on the Merger Date. Changes in these assumptions could have a significant impact on the amount of the identified intangible assets and/or the resulting amount of goodwill assigned to each reporting unit. CenterPoint Energy utilized a third-party valuation specialist in determining the key assumptions used in the valuation of intangible assets acquired and the allocation of goodwill to each of its reporting units on the Merger Date.

Impairment of Long-Lived Assets, Including Identifiable Intangibles, Goodwill, Equity Method Investments, and Investments without a Readily Determinable Fair Value

The Registrants review the carrying value of long-lived assets, including identifiable intangibles, goodwill, equity method investments, and investments without a readily determinable fair value whenever events or changes in circumstances indicate that such carrying values may not be recoverable, and at least annually, goodwill is tested for impairment as required by accounting guidance for goodwill and other intangible assets.  Unforeseen events, changes in market conditions, and probable regulatory disallowances, where applicable, could have a material effect on the value of long-lived assets, including intangibles, goodwill, equity method investments, and investments without a readily determinable fair value due to changes in observable or estimated market value, future cash flows, interest rate, and regulatory matters could result in an impairment charge. The Registrants recorded no impairments to long-lived assets, including intangibles, equity method investments, or readily determinable fair value during 2019, 2018 and 2017. CenterPoint Energy and CERC recognized goodwill impairment losses, discussed below, during 2019, and the Registrants recorded no impairments to goodwill in 2018 and 2017.

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

Fair value measurements require significant judgment and unobservable inputs, including (i) projected timing and amount of future cash flows, which factor in planned growth initiatives, (ii) the regulatory environment, as applicable, and (iii) discount rates reflecting risk inherent in the future market prices. Determining the discount rates for the non-rate regulated businesses requires the estimation of the appropriate company specific risk premiums for those non-rate regulated businesses based on evaluation of industry and entity-specific risks, which includes expectations about future market or economic conditions existing on the date of the impairment test. Changes in these assumptions could have a significant impact on results of the impairment tests. CenterPoint Energy and CERC utilized a third-party valuation specialist to determine the key assumptions used in the estimate of fair value for each of its reporting units on the date of its annual goodwill impairment test.

Annual goodwill impairment test

CenterPoint Energy and CERC completed their 2019 annual goodwill impairment test as of July 1, 2019 and determined, based on an income approach or a weighted combination of income and market approaches, that no goodwill impairment charge

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was required for any reporting unit based on the annual test. The fair values of each reporting unit significantly exceeded the carrying value of the reporting unit, with the exception of CenterPoint Energy’s Indiana Electric Integrated, Infrastructure Services and ESG reporting units. Indiana Electric Integrated’s fair value exceed its carrying value by 13%, and it had total goodwill of $1,008 million as of the 2019 annual impairment test date. Infrastructure Services’ fair value exceeded its carrying values by 6%, and it had total goodwill of $355 million as of the 2019 annual impairment test date. ESG’s fair value exceeded its carrying value by 8%, and it had total goodwill of $127 million as of the 2019 annual impairment test date. These reporting units are comprised entirely of businesses acquired in the Merger in February 2019, when assets and liabilities were adjusted to fair value and as a result, carrying values approximate fair value at that time. The measurement period for the initial purchase price accounting for the reporting units acquired in the Merger, including CenterPoint Energy’s Indiana Electric Integrated, Infrastructure Services and ESG reporting units, remained open as of the date of the annual impairment test date. Upon conclusion of the measurement period in the fourth quarter of 2019, CenterPoint Energy retrospectively evaluated the impact that the measurement period adjustments had on its annual impairment test and identified no material differences to the results, except CenterPoint Energy’s Indiana Electric Integrated’s fair value exceeded its carrying value by 7%, and it had total goodwill of $1,121 million. The primary driver for the excess fair value in the businesses acquired in the Merger at the annual goodwill impairment test date is a decline in market discounts rates, a key valuation assumption, from February 1, 2019 to July 1, 2019.

Although no goodwill impairment resulted from the 2019 annual test, an interim goodwill impairment test could be triggered by the following: actual earnings results that are materially lower than expected, significant adverse changes in the operating environment, an increase in the discount rate, changes in other key assumptions which require judgment and are forward looking in nature, if CenterPoint Energy’s market capitalization falls below book value for an extended period of time, or events affecting a reporting unit such as a contemplated disposal of all or part of a reporting unit.

Assets Held for Sale and Discontinued Operations

Generally, a long-lived asset to be sold is classified as held for sale in the period in which management, with approval from the Board of Directors, as applicable, commits to a plan to sell and a sale is expected to be completed within one year. The Registrants record assets and liabilities held for sale (the “Disposal Group”) at the lower of their carrying value or their estimated fair value less cost to sell. If the Disposal Group reflects a component of a reporting unit and meets the definition of a business, the goodwill within that reporting unit is allocated to the disposal group based on the relative fair value of the components representing a business that will be retained and disposed. Goodwill is not allocated to a portion of a reporting unit that does not meet the definition of a business. A disposal group that meets the held for sale criteria and also represents a strategic shift to the Registrant, is also reflected as discontinued operations on the Statements of Consolidated Income, and prior periods are recast to reflect the earnings or losses from such businesses as income from discontinued operations, net of tax.

December 31, 2019 goodwill impairment assessments

In connection with its preparation of financial statements for the year ended December 31, 2019, CenterPoint Energy and CERC, as applicable, identified triggering events for interim goodwill impairment tests at the Infrastructure Services and Energy Services reporting units. Early stage bids received from market participants during the exploration of strategic alternatives for these businesses at year-end indicated that the fair value of each reporting unit was more likely than not below the carrying value. As a result, CenterPoint Energy and CERC evaluated long-lived assets, including property, plant and equipment, and specifically identifiable intangibles subject to amortization, for recoverability and the goodwill within the reporting units were tested for impairment as of December 31, 2019. The long-lived assets within the Infrastructure Services and Energy Services reporting units were determined to be recoverable based on undiscounted cash flows, considering the likelihood of possible outcomes existing as of December 31, 2019, including the assessment of the likelihood of a future sale of these assets.

On February 3, 2020, CenterPoint Energy, through its subsidiary VUSI, entered into the Securities Purchase Agreement to sell the businesses within its Infrastructure Services reporting unit. Per the Securities Purchase Agreement, VISCO will be converted from a wholly-owned corporation to a limited liability company that is disregarded for federal income tax purposes immediately prior to the closing of the transaction resulting in the sale of membership units at closing.  The sale will be considered an asset sale for tax purposes requiring the net deferred tax liabilities of approximately $123 million within the reporting unit as of December 31, 2019 to be recognized as a benefit to deferred income tax expense by CenterPoint Energy upon closing; therefore, any deferred tax assets and liabilities within the reporting unit are not included in the carrying amount of the assets and liabilities that will be transferred to the buyer.

The fair value of the Infrastructure Services reporting unit was estimated as of December 31, 2019 using a market approach utilizing the economic indicators of value received by market participants during the exploration of strategic alternatives to inform the fair value of substantially all of the businesses within this reporting unit as of December 31, 2019.  As of December 31, 2019, the fair value of the Infrastructure Services reporting unit exceeded the carrying value (inclusive of deferred income tax liabilities

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of $123 million) by approximately $21 million or 2%. As a result, CenterPoint Energy did not record a goodwill impairment on its Infrastructure Services reporting unit as of December 31, 2019.

In February 2020, certain assets and liabilities representing the businesses within the Infrastructure Services reporting unit that will be transferred under the Securities Purchase Agreement (the “Disposal Group”) met the held for sale criteria. Because the transaction is structured as an asset sale for income tax purposes, the disposal group will exclude the deferred tax liabilities included within the reporting unit. Upon classifying the Disposal Group as held for sale in the first quarter of 2020, CenterPoint Energy anticipates recording an impairment loss on assets held for sale of approximately $85 million, plus an additional loss for transaction costs, in 2020. The actual amount of the impairment or loss in 2020 may be materially different from the preliminary amount.

The fair value of the Energy Services reporting unit was estimated as of December 31, 2019 using a combination of the market approach and the income approach. CenterPoint Energy and CERC utilized the economic indicators of value received by market participants during the exploration of strategic alternatives to inform the fair value of substantially all of the businesses within this reporting unit as of December 31, 2019. Certain assets groups not constituting a business within the reporting unit were valued using an income approach, as there was limited indication of value from market participants as of December 31, 2019 for these assets and liabilities.  As a result, Energy Services recognized a goodwill impairment loss of $48 million, the amount by which the carrying value (inclusive of deferred income tax liabilities of $25 million) of the Energy Services reporting unit exceeded its fair value as of December 31, 2019. Following the impairment, the carrying value of the goodwill remaining in the Energy Services reporting unit is $62 million as of December 31, 2019.

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. Per the Equity Purchase Agreement, CES will be converted from a wholly-owned corporation to a limited liability company that is disregarded for federal income tax purposes immediately prior to the closing of the transaction resulting in the sale of membership units at closing. The sale will be considered an asset sale for tax purposes requiring the net deferred tax liabilities of approximately $25 million within the reporting unit as of December 31, 2019 to be recognized as a benefit to deferred income tax expense by CenterPoint Energy upon closing; therefore, any deferred tax assets and liabilities within the reporting unit are not included in the carrying amount of the assets and liabilities that will be transferred to the buyer.

In February 2020 certain assets and liabilities representing substantially all of the businesses within CenterPoint Energy’s and CERC’s Energy Services reporting unit met the criteria to be classified as held for sale. Because the transaction is structured as an asset sale for income tax purposes, the disposal group will exclude the deferred tax liabilities and certain assets and liabilities within the reporting unit that will be retained by CenterPoint Energy and CERC upon closing. Upon classifying the disposal group as held for sale in the first quarter of 2020, CenterPoint Energy anticipates recording an aggregate impairment loss on assets held for sale of approximately $80 million, plus an additional loss for transaction costs, in the first quarter of 2020. The actual amount of the impairment or loss may be materially different from the preliminary amount.

For further information, see Notes 6 and 23 to the consolidated financial statements.

Equity Method Investments

Equity method investments are evaluated for impairment when factors indicate that a decrease in value of an investment has occurred and the carrying amount of the investment may not be recoverable. An impairment loss, based on the excess of the carrying value over the best estimate of fair value of the investment, is recognized in earnings when an impairment is deemed to be other than temporary. Considerable judgment is used in determining if an impairment loss is other than temporary and the amount of any impairment.

Based on an analysis of CenterPoint Energy’s investment in Enable as of December 31, 2019, CenterPoint Energy believes that the decline in the value of Enable is temporary, and that the carrying value of its investment of $2.4 billion will be recovered. CenterPoint Energy considers the severity and duration of the impairment, management’s intent and ability to hold the investment to recovery, significant events and conditions of Enable, including its investment grade credit rating and planned expansion projects, along with other factors, to conclude that the investment is not other than temporarily impaired as of December 31, 2019. A sustained low Enable common unit price or further declines in such price could result in CenterPoint Energy recording an impairment charge in future periods. If the decrease in value of CenterPoint Energy’s investment in Enable is determined to be other than temporary, an impairment will be recognized equal to the excess of the carrying value of the investment in Enable over its estimated fair value. Management would evaluate and likely weight both the income approach and market approach to estimate the fair value of the total investment in Enable, which includes CenterPoint Energy’s holdings of Enable common units, general partner interest and incentive distribution rights. The determination of fair value will consider a number of relevant factors including Enable’s

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forecasted results, recent comparable transactions and the limited float of Enable’s publicly traded common units. As of December 31, 2019, the carrying value of CenterPoint Energy’s total investment in Enable was $10.29 per unit. On December 31, 2019, Enable’s common unit price closed at $10.03, based on its publicly traded common units which represent approximately 21% of total outstanding units, (an aggregate of approximately $61 million below carrying value). On February 24, 2020, Enable’s common unit price closed at $7.63 (approximately $622 million below carrying value).

Unbilled Revenues

Revenues related to electricity delivery and natural gas sales and services are generally recognized upon delivery to customers. However, the determination of deliveries to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month either electronically through AMS meter communications or manual readings. At the end of each month, deliveries to non-AMS customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is estimated. Information regarding deliveries to AMS customers after the last billing is obtained from actual AMS meter usage data. Unbilled electricity delivery revenue is estimated each month based on actual AMS meter data, daily supply volumes and applicable rates. Unbilled natural gas sales are estimated based on estimated purchased gas volumes, estimated lost and unaccounted for gas and tariffed rates in effect. As additional information becomes available, or actual amounts are determinable, the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates.

Infrastructure Services provides underground pipeline construction and repair services. The contracts are generally less than one year in duration and consist of fixed price, unit, and time and material customer contracts. Under unit or time and material contracts, services are billed to customers monthly or more frequently for work completed based on units completed or the costs of time and material incurred and generally require payment within 30 days of billing. Infrastructure Services has the right to consideration from customers in an amount that corresponds directly with the performance obligation satisfied, and therefore recognizes revenue at a point in time in the amount to which it has the right to invoice, which results in accrued unbilled revenues at the end of each accounting period. Under fixed price contracts, Infrastructure Services performs larger scale construction and repair services. Services performed under fixed price contracts are typically billed per the terms of the contract, which can range from completion of specific milestones to scheduled billing intervals. Billings occur monthly or more frequently for work completed and generally require payment within 30 days of billing. Revenue for fixed price contracts is recognized over time as control is transferred using the input method, considering costs incurred relative to total expected cost. Total expected cost is therefore a significant judgment affecting the amount and timing of revenue recognition.

Pension and Other Retirement Plans

CenterPoint Energy sponsors pension and other retirement plans in various forms covering all employees who meet eligibility requirements. CenterPoint Energy uses several statistical and other factors that attempt to anticipate future events in calculating the expense and liability related to its plans. These factors include assumptions about the discount rate, expected return on plan assets and rate of future compensation increases as estimated by management, within certain guidelines. In addition, CenterPoint Energy’s actuarial consultants use subjective factors such as withdrawal and mortality rates. The actuarial assumptions used may differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal rates or longer or shorter life spans of participants. These differences may result in a significant impact to the amount of pension and other retirement plans expense recorded. Please read “— Other Significant Matters — Pension Plans” for further discussion.

NEW ACCOUNTING PRONOUNCEMENTS

See Note 2(u) to the consolidated financial statements, incorporated herein by reference, for a discussion of new accounting pronouncements that affect the Registrants.

OTHER SIGNIFICANT MATTERS

Pension Plans (CenterPoint Energy).  As discussed in Note 8(b) to the consolidated financial statements, CenterPoint Energy maintains a non-contributory qualified defined benefit pension plan covering eligible employees. Employer contributions for the qualified plan are based on actuarial computations that establish the minimum contribution required under ERISA and the maximum deductible contribution for income tax purposes.

Under the terms of CenterPoint Energy’s pension plan, it reserves the right to change, modify or terminate the plan. CenterPoint Energy’s funding policy is to review amounts annually and contribute an amount at least equal to the minimum contribution required under ERISA.

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Additionally, CenterPoint Energy maintains unfunded non-qualified benefit restoration plans that allows participants to receive the benefits to which they would have been entitled under the non-contributory qualified pension plan except for the federally mandated limits on qualified plan benefits or on the level of compensation on which qualified plan benefits may be calculated.

CenterPoint Energy’s funding requirements and employer contributions for the years ended December 31, 2019, 2018 and 2017 were as follows:

	Year Ended December 31,
	2019		2018		2017
CenterPoint Energy	(in millions)
Minimum funding requirements for qualified pension plans	$	86	$	60	$	39
Employer contributions to the qualified pension plans	86		60		39
Employer contributions to the non-qualified benefit restoration plans	23		9		9

CenterPoint Energy expects to contribute a minimum of approximately $76 million to the qualified pension plans and contributions aggregating approximately $7 million to the non-qualified benefit restoration plans in 2020.

Changes in pension obligations and assets may not be immediately recognized as pension expense in CenterPoint Energy’s Statements of Consolidated Income, but generally are recognized in future years over the remaining average service period of plan participants. As such, significant portions of pension expense recorded in any period may not reflect the actual level of benefit payments provided to plan participants.

As the sponsor of a plan, CenterPoint Energy is required to (a) recognize on its Consolidated Balance Sheet an asset for the plan’s over-funded status or a liability for the plan’s under-funded status, (b) measure a plan’s assets and obligations as of the end of the fiscal year and (c) recognize changes in the funded status of the plans in the year that changes occur through adjustments to other comprehensive income and, when related to its rate-regulated utilities with recoverability of cost, to regulatory assets.

The projected benefit obligation for all defined benefit pension plans was $2.5 billion and $2.0 billion as of December 31, 2019 and 2018, respectively.

As of December 31, 2019, the projected benefit obligation exceeded the market value of plan assets of CenterPoint Energy’s pension plans by $448 million. Changes in interest rates or the market values of the securities held by the plan during 2020 could materially, positively or negatively, change the funded status and affect the level of pension expense and required contributions.

Houston Electric and CERC participate in CenterPoint Energy’s qualified and non-qualified pension plans covering substantially all employees. Pension cost and the impact to pre-tax earnings, after capitalization and regulatory impacts, by Registrant were as follows:

	Year Ended December 31,
	2019						2018						2017
	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC
	(in millions)
Pension cost	$	93	$	40	$	35	$	61	$	25	$	22	$	95	$	42	$	35
Impact to pre-tax earnings	72		23		31		64		27		23		71		23		29

The calculation of pension cost and related liabilities requires the use of assumptions. Changes in these assumptions can result in different expense and liability amounts, and future actual experience can differ from the assumptions. Two of the most critical assumptions are the expected long-term rate of return on plan assets and the assumed discount rate.

As of December 31, 2019, CenterPoint Energy’s qualified pension plans had an expected long-term rate of return on plan assets of 5.75%, which is 0.25% lower than the 6.00% rate assumed as of December 31, 2018. The expected rate of return assumption was developed using the targeted asset allocation of our plans and the expected return for each asset class. CenterPoint Energy regularly reviews its actual asset allocation and periodically rebalances plan assets to reduce volatility and better match plan assets and liabilities.

As of December 31, 2019, the projected benefit obligation was calculated assuming a discount rate of 3.20%, which is 1.15% lower than the 4.35% discount rate assumed as of December 31, 2018. The discount rate was determined by reviewing yields on

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high-quality bonds that receive one of the two highest ratings given by a recognized rating agency and the expected duration of pension obligations specific to the characteristics of CenterPoint Energy’s plans.

CenterPoint Energy’s actuarially determined pension and other postemployment expense for 2019 and 2018 that is greater or less than the amounts being recovered through rates in certain Texas jurisdictions is deferred as a regulatory asset or liability, respectively.  Pension cost for 2020, including the nonqualified benefit restoration plan, is estimated to be $45 million, of which CenterPoint Energy expects approximately $52 million to impact pre-tax earnings after effecting such deferrals and capitalization, based on an expected return on plan assets of 5.75% and a discount rate of 3.20% as of December 31, 2019. If the expected return assumption were lowered by 0.50% from 5.75% to 5.25%, 2020 pension cost would increase by approximately $10 million.

As of December 31, 2019, the pension plans projected benefit obligation, including the unfunded nonqualified pension plans, exceeded plan assets by $448 million.  If the discount rate were lowered by 0.50% from 3.20% to 2.70%, the assumption change would increase CenterPoint Energy’s projected benefit obligation by approximately $127 million and decrease its 2020 pension cost by approximately $5 million. The expected reduction in pension cost due to the decrease in discount rate is a result of the expected correlation between the reduced interest rate and appreciation of fixed income assets in pension plans with significantly more fixed income instruments than equity instruments. In addition, the assumption change would impact CenterPoint Energy’s Consolidated Balance Sheets by increasing the regulatory asset recorded as of December 31, 2019 by $110 million and would result in a charge to comprehensive income in 2019 of $13 million, net of tax of $4 million, due to the increase in the projected benefit obligation.

Future changes in plan asset returns, assumed discount rates and various other factors related to the pension plans will impact CenterPoint Energy’s future pension expense and liabilities. CenterPoint Energy cannot predict with certainty what these factors will be in the future.

Item 7A.     Quantitative and Qualitative Disclosures About Market Risk

Impact of Changes in Interest Rates, Equity Prices and Energy Commodity Prices

The Registrants are exposed to various market risks. These risks arise from transactions entered into in the normal course of business and are inherent in the Registrants’ consolidated financial statements. Most of the revenues and income from the Registrants’ business activities are affected by market risks. Categories of market risk include exposure to commodity prices through non-trading activities, interest rates and equity prices. A description of each market risk is set forth below:

• Interest rate risk primarily results from exposures to changes in the level of borrowings and changes in interest rates.

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

• Commodity price risk results from exposures to changes in spot prices, forward prices and price volatilities of commodities, such as natural gas, NGLs and other energy commodities (CenterPoint Energy and CERC).

Management has established comprehensive risk management policies to monitor and manage these market risks.

Interest Rate Risk

As of December 31, 2019, the Registrants had outstanding long-term debt and lease obligations and CenterPoint Energy had obligations under its ZENS that subject them to the risk of loss associated with movements in market interest rates.

CenterPoint Energy’s floating rate obligations aggregated $3.9 billion and $210 million as of December 31, 2019 and 2018, respectively. If the floating interest rates were to increase by 10% from December 31, 2019 rates, CenterPoint Energy’s combined interest expense would increase by approximately $9 million annually.

Houston Electric did not have any floating rate obligations as of either December 31, 2019 or 2018.

CERC’s floating rate obligations aggregated $376 million and $210 million as of December 31, 2019 and 2018, respectively. If the floating interest rates were to increase by 10% from December 31, 2019 rates, CERC’s combined interest expense would increase by approximately $1 million annually.

As of December 31, 2019 and 2018, CenterPoint Energy had outstanding fixed-rate debt (excluding indexed debt securities) aggregating $11.2 billion and $9.0 billion, respectively, in principal amount and having a fair value of $12.2 billion and $9.2 billion,

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respectively. Because these instruments are fixed-rate, they do not expose CenterPoint Energy to the risk of loss in earnings due to changes in market interest rates. However, the fair value of these instruments would increase by approximately $344 million if interest rates were to decline by 10% from their levels as of December 31, 2019.

As of December 31, 2019 and 2018, Houston Electric had outstanding fixed-rate debt aggregating $5.0 billion and $4.8 billion, respectively, in principal amount and having a fair value of approximately $5.5 billion and $4.8 billion, respectively. Because these instruments are fixed-rate, they do not expose Houston Electric to the risk of loss in earnings due to changes in market interest rates. However, the fair value of these instruments would increase by approximately $179 million if interest rates were to decline by 10% from their levels as of December 31, 2019.

As of December 31, 2019 and 2018, CERC had outstanding fixed-rate debt aggregating $2.2 billion and $2.2 billion, respectively, in principal amount and having a fair value of $2.5 billion and $2.3 billion, respectively. Because these instruments are fixed-rate, they do not expose CERC to the risk of loss in earnings due to changes in market interest rates. However, the fair value of these instruments would increase by approximately $77 million if interest rates were to decline by 10% from their levels at December 31, 2019.

In general, such an increase in fair value would impact earnings and cash flows only if the Registrants were to reacquire all or a portion of these instruments in the open market prior to their maturity.

As discussed in Note 12 to the consolidated financial statements, the ZENS obligation is bifurcated into a debt component and a derivative component. The debt component of $19 million at December 31, 2019 was a fixed-rate obligation and, therefore, did not expose CenterPoint Energy to the risk of loss in earnings due to changes in market interest rates. However, the fair value of the debt component would increase by approximately $2 million if interest rates were to decline by 10% from levels at December 31, 2019. Changes in the fair value of the derivative component, a $893 million recorded liability at December 31, 2019, are recorded in CenterPoint Energy’s Statements of Consolidated Income and, therefore, it is exposed to changes in the fair value of the derivative component as a result of changes in the underlying risk-free interest rate. If the risk-free interest rate were to increase by 10% from December 31, 2019 levels, the fair value of the derivative component liability would decrease by approximately $1 million, which would be recorded as an unrealized gain in CenterPoint Energy’s Statements of Consolidated Income.

Equity Market Value Risk (CenterPoint Energy)

CenterPoint Energy is exposed to equity market value risk through its ownership of 10.2 million shares of AT&T Common and 0.9 million shares of Charter Common, which CenterPoint Energy holds to facilitate its ability to meet its obligations under the ZENS. See Note 12 to the consolidated financial statements for a discussion of CenterPoint Energy’s ZENS obligation. Changes in the fair value of the ZENS-Related Securities held by CenterPoint Energy are expected to substantially offset changes in the fair value of the derivative component of the ZENS. A decrease of 10% from the December 31, 2019 aggregate market value of these shares would result in a net loss of less than $1 million, which would be recorded as a loss on debt securities in CenterPoint Energy’s Statements of Consolidated Income.

Commodity Price Risk From Non-Trading Activities (CenterPoint Energy and CERC)

CenterPoint Energy and CERC use derivative instruments as economic hedges to offset the commodity price exposure inherent in their businesses. The commodity risk created by these instruments, including the offsetting impact on the market value of natural gas inventory, is described below. CenterPoint Energy and CERC measure this commodity risk using a sensitivity analysis. For purposes of this analysis, CenterPoint Energy and CERC estimate commodity price risk by applying a $0.50 change in the forward NYMEX price to their net open fixed price position (including forward fixed price physical contracts, natural gas inventory and fixed price financial contracts) at the end of each period. As of December 31, 2019, the recorded fair value of CenterPoint Energy’s and CERC’s non-trading energy derivatives was a net asset of $73 million (before collateral), all of which is related to CenterPoint Energy’s and CERC’s Energy Services reportable segment. A $0.50 change in the forward NYMEX price would have had a combined impact of $13 million on CenterPoint Energy’s and CERC’s non-trading energy derivatives net asset and the market value of natural gas inventory.

Commodity price risk is not limited to changes in forward NYMEX prices. Variation of commodity pricing between the different indices used to mark to market portions of CenterPoint Energy’s and CERC’s natural gas inventory (Gas Daily) and the related fair value hedge (NYMEX) can result in volatility to CenterPoint Energy’s and CERC’s net income. Over time, any gains or losses on the sale of storage gas inventory would be offset by gains or losses on the fair value hedges.

100

CenterPoint Energy’s regulated operations in Indiana have limited exposure to commodity price risk for transactions involving purchases and sales of natural gas, coal and purchased power for the benefit of retail customers due to current state regulations, which, subject to compliance with those regulations, allow for recovery of the cost of such purchases through natural gas and fuel cost adjustment mechanisms. CenterPoint Energy’s utility natural gas operations in Indiana have regulatory authority to lock in pricing for up to 50% of annual natural gas purchases using arrangements with an original term of up to 10 years. This authority has been utilized to secure fixed price natural gas using both physical purchases and financial derivatives. As of December 31, 2019, the recorded fair value of non-trading energy derivative liabilities was $22 million for CenterPoint Energy’s utility natural gas operations in Indiana, which is offset by a regulatory asset.

Although CenterPoint Energy’s regulated operations are exposed to limited commodity price risk, natural gas and coal prices have other effects on working capital requirements, interest costs, and some level of price-sensitivity in volumes sold or delivered. Constructive regulatory orders, such as those authorizing lost margin recovery, other innovative rate designs and recovery of unaccounted for natural gas and other natural gas-related expenses, also mitigate the effect natural gas costs may have on CenterPoint Energy’s financial condition. In 2008, the PUCO approved an exit of the merchant function in CenterPoint Energy’s Ohio natural gas service territory, allowing Ohio customers to purchase substantially all natural gas directly from retail marketers rather than from CenterPoint Energy.

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Item 8.        Financial Statements and Supplementary Data

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

CenterPoint Energy, Inc.

Houston, Texas

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of CenterPoint Energy, Inc. and subsidiaries (the “Company”) as of December 31, 2019 and 2018, the related statements of consolidated income, comprehensive income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2019, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 27, 2020 expressed an unqualified opinion on the Company's internal control over financial reporting.

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Acquisitions - Vectren Corporation - Intangible Assets - Refer to Note 4 to the financial statements

Critical Audit Matter Description

The Company completed the acquisition of Vectren Corporation (“Vectren”) for $6 billion in cash on February 1, 2019. The Company accounted for the acquisition under the acquisition method of accounting for business combinations. Accordingly, the purchase price was allocated to the assets acquired and liabilities assumed based on their respective fair values, including intangible assets and goodwill of $4.6 billion. Of the intangible assets acquired, $297 million was allocated to identifiable intangible assets such as customer relationships and trade name with the remainder of $4.3 billion being recorded as goodwill. Management estimated the fair value of the identifiable intangible assets using the multi-period excess earnings method, which is a specific discounted cash flow method. In addition, the determination of the business fair value required management to make significant estimates and assumptions related to discount rates and future cash flows. Determining the discount rates for the nonregulated businesses acquired required management to estimate the appropriate entity specific risk premiums for those nonregulated businesses based on evaluation of industry and entity-specific risks which included expectations about future market or economic conditions.

102

Changes in these assumptions could have a significant impact on either the amount of the identified intangible assets, the resulting amount of goodwill, or both.

Given the fair value determination of intangible assets acquired required management to make significant estimates and assumptions related to the forecasts of future cash flows and the company specific risk premium affecting the discount rate, performing audit procedures to evaluate the reasonableness of these estimates and assumptions required a high degree of auditor judgment and an increased extent of effort.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the forecasts of future cash flows and company specific risk premium affecting the discount rate for the intangible assets of the nonregulated businesses acquired included the following, among others:

• We tested the effectiveness of controls over acquisition valuation, including management’s controls over the forecasts of future cash flows and selection of the company specific risk premium assumption used in the determinations of the discount rates.

• We considered the impact of changes to the discount rate and long-term growth rate on the fair value.

• We evaluated the value at which acquired assets were recorded under the applicable accounting guidance based on the regulated nature of the entity.

• We assessed the reasonableness of management’s forecasts by comparing the forecasts to:

◦ Historical revenues and operating margins.

◦ Internal communications to management and the Board of Directors.

◦ Forecasted information included in Company press releases as well as in analyst and industry reports for the Company and certain of its peer companies.

• We evaluated whether the estimated future cash flows were consistent with evidence obtained in other areas of the audit.

• We involved our fair value specialists who assisted in:

◦ Assessing the appropriateness of the valuation methodology used to determine the customer relationship intangible assets and the company specific risk premiums.

◦ Testing the determined discount rates by independently estimating a discount rate for each business using a process consistent with generally accepted valuation practices.

Goodwill - Refer to Note 6 to the financial statements

Critical Audit Matter Description

The Company’s evaluation of goodwill for impairment involves the comparison of the fair value of each reporting unit to its carrying value. In its annual goodwill impairment test on July 1, 2019 (“measurement date”) and as triggering events are identified, the Company used the discounted cash flow model and a market approach to estimate fair value of each reporting unit, which required management to make significant estimates and assumptions related to forecasts of future revenues and operating margins based on certain assumptions including (i) future capital expenditures and rate base growth, (ii) estimated future rate changes, (iii) discount rates, and (iv) long-term growth rates. Changes in these assumptions could have a significant impact on the fair value of a reporting unit, the amount of any goodwill impairment charge, or both. The Company’s goodwill is $5.2 billion as of December 31, 2019, of which $4.3 billion resulted from the acquisition of Vectren. The fair value of each reporting unit exceeded the carrying value as of the measurement date and, therefore, no impairment was recognized.

Given the significant assumptions used by management to estimate fair value including (i) future capital expenditures and rate base growth, (ii) estimated future rate changes, (iii) discount rates, and (iv) long-term growth rates, performing audit procedures to evaluate the reasonableness of management’s estimates and assumptions related to forecasts of future revenue and operating margin, specifically for reporting units containing unregulated business units and Vectren rate regulated jurisdictions, required a high degree of auditor judgment and an increased extent of effort, including the need to involve fair value specialists.

103

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the assumptions used to forecast future revenue and operating margin used by management within the discounted cash flow model included the following, among others:

• We tested the effectiveness of controls over management’s goodwill impairment evaluation, including those over the determination of fair value, such as controls related to management’s forecasts of future capital expenditures, future rate base growth, estimated future rate changes, discount rates, and long-term growth rates.

• We evaluated the reasonableness of management’s forecasts by comparing the forecasts to:

◦ Historical revenues, operating margins, capital expenditures, rate base growth, and rate changes.

◦ Internal communications to management and the Board of Directors.

◦ Forecasted information included in Company press releases as well as in analyst and industry reports for the Company and certain of its peer companies.

• We compared future rate changes to the Company’s scheduled rate filings and the amount of capital expenditures for the regulated entities to communications with regulators including integrated resource plans.

• We compared actual revenue growth and capital expenditures results for 2019 to the planned results as of the acquisition date.

• We evaluated the impact of changes in management’s forecasts from the measurement date to December 31, 2019.

• We involved our fair value specialists who assisted in:

◦ Assessing the appropriateness of the valuation methodology used to determine the company specific risk premiums in calculating the discount rate.

◦ Testing the determined discount rates by independently estimating a discount rate for each business using a process consistent with generally accepted valuation practices.

◦ Evaluating the reasonableness of the long-term growth rate through a comparison to industry reports and peer companies.

Impact of Rate Regulation on the Financial Statements - Refer to Notes 2 and 7 to the financial statements

Critical Audit Matter Description

The Company, through its regulated electric and gas subsidiaries is subject to rate regulation by the relevant state public utility commissions and, in Texas by the Railroad Commission, and the Federal Energy Regulatory Commission (collectively, “the Commissions”), and those municipalities (in Texas only) served by the Company. Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant, and equipment, net; regulatory assets and liabilities; utility revenues; operation and maintenance expense; and depreciation and amortization expense; and income tax expense.

The Company’s rates are subject to regulatory rate-setting processes by certain municipalities and the Commissions. Rates are determined and approved in regulatory proceedings based on an analysis of the Company’s costs to provide utility service and a return on, and recovery of, the Company’s investment in the utility business. Regulatory decisions can have an impact on the recovery of costs, the rate of return earned on investment, and the timing and amount of assets to be recovered by rates. The regulation of rates is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital. Decisions to be made by the Commissions in the future will impact the accounting for regulated operations, including decisions about the amount of allowable costs and return on invested capital included in rates and any refunds that may be required. While the Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that the Commissions will not approve: (1) full recovery of the costs of providing utility service, or (2) full recovery of all amounts invested in the utility business and a reasonable return on that investment.

104

We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about affected account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory actions on the financial statements. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs, (2) a disallowance of capital investments made by the Company and (3) refunds to customers. Given that management’s accounting judgments are based on assumptions about the outcome of future decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due its inherent complexities.

How the Critical Audit Matter Was Addressed in the Audit

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

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

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

• For matters with a high degree of subjectivity, we read relevant regulatory orders issued by the Commissions for the Company and other public utilities in the states the Company operates in, regulatory statutes, interpretations, procedural memorandums, filings made by interveners, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedence of the Commissions’ treatment of similar costs under similar circumstances. We evaluated the external information and compared to management’s recorded regulatory asset and liability balances for completeness.

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

• We evaluated management’s plans regarding property, plant, and equipment for indications of potential impairment. We inspected the capital-projects budget and inquired of management to identify projects that are designed to replace assets that may be retired prior to the end of the useful life. We inspected minutes of the board of directors and regulatory orders and other filings with the Commissions to identify any evidence that may contradict management’s assertion regarding probability of a disallowance of long-lived assets.

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

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

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

February 27, 2020 

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

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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED INCOME

	Year Ended December 31,
	2019			2018			2017
	(in millions, except per share amounts)
Revenues:
Utility revenues	$	7,162		$	6,163		$	5,603
Non-utility revenues	5,139			4,426			4,011
Total	12,301			10,589			9,614
Expenses:
Utility natural gas, fuel and purchased power	1,683			1,410			1,109
Non-utility cost of revenues, including natural gas	4,029			4,364			3,785
Operation and maintenance	3,550			2,335			2,157
Depreciation and amortization	1,287			1,243			1,036
Taxes other than income taxes	478			406			391
Goodwill impairment	48			—			—
Total	11,075			9,758			8,478
Operating Income	1,226			831			1,136
Other Income (Expense):
Gain (loss) on marketable securities	282			(22		)	7
Gain (loss) on indexed debt securities	(292		)	(232		)	49
Interest and other finance charges	(528		)	(361		)	(313		)
Interest on Securitization Bonds	(39		)	(59		)	(77		)
Equity in earnings of unconsolidated affiliates, net	230			307			265
Other, net	50			50			(4		)
Total	(297		)	(317		)	(73		)
Income Before Income Taxes	929			514			1,063
Income tax expense (benefit)	138			146			(729		)
Net Income	791			368			1,792
Preferred stock dividend requirement	117			35			—
Income Available to Common Shareholders	$	674		$	333		$	1,792
Basic Earnings Per Common Share	$	1.34		$	0.74		$	4.16
Diluted Earnings Per Common Share	$	1.33		$	0.74		$	4.13
Weighted Average Common Shares Outstanding, Basic	502			449			431
Weighted Average Common Shares Outstanding, Diluted	505			452			434

See Combined Notes to Consolidated Financial Statements

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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME

	Year Ended December 31,
	2019			2018			2017
	(in millions)
Net income	$	791		$	368		$	1,792
Other comprehensive income (loss):
Adjustment to pension and other postretirement plans (net of tax expense (benefit) of $4, ($2) and $6, respectively)	12			(10		)	6
Net deferred gain (loss) from cash flow hedges (net of tax expense (benefit) of ($1), ($4) and ($2), respectively)	(2		)	(15		)	(3		)
Reclassification of deferred loss from cash flow hedges realized in net income (net of tax expense of $-0-, $-0- and $-0-, respectively)	1			—			—
Other comprehensive loss from unconsolidated affiliates (net of tax of $-0-, $-0-, and $-0-, respectively)	(1		)	—			—
Other comprehensive income (loss)	10			(25		)	3
Comprehensive income	801			343			1795
Preferred stock dividend requirement	117			35			—
Comprehensive income available to common shareholders	$	684		$	308		$	1,795

See Combined Notes to Consolidated Financial Statements

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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

	December 31, 2019		December 31, 2018
	(in millions)
ASSETS
Current Assets:
Cash and cash equivalents ($216 and $335 related to VIEs, respectively)	$	241	$	4,231
Investment in marketable securities	822		540
Accounts receivable ($26 and $56 related to VIEs, respectively), less bad debt reserve of $21 and $18, respectively	1,249		1,190
Accrued unbilled revenues	586		378
Natural gas and coal inventory	277		194
Materials and supplies	269		200
Non-trading derivative assets	136		100
Taxes receivable	106		—
Prepaid expense and other current assets ($19 and $34 related to VIEs, respectively)	161		192
Total current assets	3,847		7,025
Property, Plant and Equipment, net	20,945		14,044
Other Assets:
Goodwill	5,164		867
Regulatory assets ($788 and $1,059 related to VIEs, respectively)	2,117		1,967
Non-trading derivative assets	58		38
Investment in unconsolidated affiliates	2,408		2,482
Preferred units - unconsolidated affiliate	363		363
Intangible assets, net	321		65
Other	216		158
Total other assets	10,647		5,940
Total Assets	$	35,439	$	27,009

See Combined Notes to Consolidated Financial Statements

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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS, cont.

	December 31, 2019			December 31, 2018
	(in millions, except par value and shares)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities:
Current portion of VIE Securitization Bonds long-term debt	$	231		$	458
Indexed debt, net	19			24
Current portion of other long-term debt	618			—
Indexed debt securities derivative	893			601
Accounts payable	1,138			1,240
Taxes accrued	241			204
Interest accrued	158			121
Dividends accrued	—			187
Customer deposits	125			86
Non-trading derivative liabilities	51			126
Other	414			255
Total current liabilities	3,888			3,302
Other Liabilities:
Deferred income taxes, net	3,928			3,239
Non-trading derivative liabilities	29			5
Benefit obligations	754			796
Regulatory liabilities	3,474			2,525
Other	763			402
Total other liabilities	8,948			6,967
Long-term Debt:
VIE Securitization Bonds, net	746			977
Other long-term debt, net	13,498			7,705
Total long-term debt, net	14,244			8,682
Commitments and Contingencies (Note 16)
Shareholders’ Equity:
Cumulative preferred stock, $0.01 par value, 20,000,000 shares authorized	—			—
Series A Preferred Stock, $0.01 par value, $800 aggregate liquidation preference, 800,000 shares outstanding	790			790
Series B Preferred Stock, $0.01 par value, $978 aggregate liquidation preference, 977,500 shares outstanding	950			950
Common stock, $0.01 par value, 1,000,000,000 shares authorized, 502,242,061 shares and 501,197,784 shares outstanding, respectively	5			5
Additional paid-in capital	6,080			6,072
Retained earnings	632			349
Accumulated other comprehensive loss	(98		)	(108		)
Total shareholders’ equity	8,359			8,058
Total Liabilities and Shareholders’ Equity	$	35,439		$	27,009

See Combined Notes to Consolidated Financial Statements

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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED CASH FLOWS

	Year Ended December 31,
	2019			2018			2017
	(in millions)
Cash Flows from Operating Activities:
Net income	$	791		$	368		$	1,792
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	1,287			1,243			1,036
Amortization of deferred financing costs	29			48			24
Deferred income taxes	69			48			(770		)
Amortization of intangible assets in Non-utility cost of revenues	24			—			—
Goodwill impairment	48			—			—
Unrealized loss (gain) on marketable securities	(282		)	22			(7		)
Loss (gain) on indexed debt securities	292			232			(49		)
Write-down of natural gas inventory	4			2			—
Equity in earnings of unconsolidated affiliates	(230		)	(307		)	(265		)
Distributions from unconsolidated affiliates	261			267			—
Pension contributions	(109		)	(69		)	(48		)
Changes in other assets and liabilities, excluding acquisitions:
Accounts receivable and unbilled revenues, net	226			(154		)	(216		)
Inventory	(52		)	1			(7		)
Taxes receivable	(106		)	—			30
Accounts payable	(455		)	220			136
Fuel cost recovery	92			33			(85		)
Non-trading derivatives, net	(64		)	103			(84		)
Margin deposits, net	(56		)	5			(55		)
Interest and taxes accrued	54			40			5
Net regulatory assets and liabilities	(114		)	28			(107		)
Other current assets	(22		)	—			(3		)
Other current liabilities	(107		)	(24		)	34
Other assets	103			6			(4		)
Other liabilities	(54		)	12			36
Other, net	9			12			24
Net cash provided by operating activities	1,638			2,136			1,417
Cash Flows from Investing Activities:
Capital expenditures	(2,506		)	(1,651		)	(1,426		)
Acquisitions, net of cash acquired	(5,991		)	—			(132		)
Distributions from unconsolidated affiliates in excess of cumulative earnings	42			30			297
Proceeds from sale of marketable securities	—			398			—
Proceeds from sale of assets	5			—			—
Purchase of investments	(6		)	—			—
Other, net	35			16			4
Net cash used in investing activities	(8,421		)	(1,207		)	(1,257		)
Cash Flows from Financing Activities:
Increase (decrease) in short-term borrowings, net	—			(39		)	4
Proceeds from (payments of) commercial paper, net	1,891			(1,543		)	349
Proceeds from long-term debt, net	2,916			2,495			1,096
Payments of long-term debt	(1,302		)	(484		)	(1,211		)
Loss on reacquired debt	—			—			(5		)
Debt and equity issuance costs	(20		)	(47		)	(13		)
Payment of dividends on Common Stock	(577		)	(499		)	(461		)
Payment of dividends on preferred stock	(118		)	(11		)	—
Proceeds from issuance of Common Stock, net	—			1,844			—
Proceeds from issuance of preferred stock, net	—			1,740			—
Distribution to ZENS holders	—			(398		)	—
Other, net	(14		)	(5		)	(4		)
Net cash provided by (used in) financing activities	2,776			3,053			(245		)
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	(4,007		)	3,982			(85		)
Cash, Cash Equivalents and Restricted Cash at Beginning of Year	4,278			296			381
Cash, Cash Equivalents and Restricted Cash at End of Year	$	271		$	4,278		$	296

See Combined Notes to Consolidated Financial Statements

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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED CHANGES IN EQUITY

	2019				2018				2017
	Shares	Amount			Shares	Amount			Shares	Amount
	(in millions of dollars and shares, except per share amounts)
Cumulative Preferred Stock, $0.01 par value; authorized 20,000,000 shares
Balance, beginning of year	2	$	1,740		—	$	—		—	$	—
Issuances of Series A Preferred Stock	—	—			1	790			—	—
Issuances of Series B Preferred Stock	—	—			1	950			—	—
Balance, end of year	2	1,740			2	1,740			—	—
Common Stock, $0.01 par value; authorized 1,000,000,000 shares
Balance, beginning of year	501	5			431	4			431	4
Issuances related to benefit and investment plans	1	—			—	—			—	—
Issuances of Common Stock	—	—			70	1			—	—
Balance, end of year	502	5			501	5			431	4
Additional Paid-in-Capital
Balance, beginning of year		6,072				4,209				4,195
Issuances related to benefit and investment plans		8				19				14
Issuances of Common Stock, net of issuance costs		—				1,844				—
Balance, end of year		6,080				6,072				4,209
Retained Earnings (Accumulated Deficit)
Balance, beginning of year		349				543				(668		)
Net income		791				368				1,792
Common Stock dividends declared ($0.8625, $1.1200 and $1.3475 per share, respectively)		(433		)		(523		)		(581		)
Series A Preferred Stock dividends declared ($30.6250, $32.1563 and $-0- per share, respectively)		(24		)		(26		)		—
Series B Preferred Stock dividends declared ($52.5000, $29.1667 and $-0- per share, respectively)		(51		)		(28		)		—
Adoption of ASU 2018-02		—				15				—
Balance, end of year		632				349				543
Accumulated Other Comprehensive Loss
Balance, beginning of year		(108		)		(68		)		(71		)
Other comprehensive income (loss)		10				(25		)		3
Adoption of ASU 2018-02		—				(15		)		—
Balance, end of year		(98		)		(108		)		(68		)
Total Shareholders’ Equity		$	8,359			$	8,058			$	4,688

See Combined Notes to Consolidated Financial Statements

111

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Member of

CenterPoint Energy Houston Electric, LLC

Houston, Texas

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of CenterPoint Energy Houston Electric, LLC and subsidiaries (the “Company”, an indirect wholly owned subsidiary of CenterPoint Energy, Inc.) as of December 31, 2019 and 2018, the related statements of consolidated income, comprehensive income, changes in equity, and cash flows, for each of the three years in the period ended December 31, 2019, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

February 27, 2020

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

112

CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC AND SUBSIDIARIES

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

STATEMENTS OF CONSOLIDATED INCOME

	Year Ended December 31,
	2019			2018			2017
	(in millions)
Revenues	$	2,990		$	3,234		$	2,998
Expenses:
Operation and maintenance	1,477			1,452			1,402
Depreciation and amortization	648			917			724
Taxes other than income taxes	247			240			235
Total	2,372			2,609			2,361
Operating Income	618			625			637
Other Income (Expense):
Interest and other finance charges	(164		)	(138		)	(128		)
Interest on Securitization Bonds	(39		)	(59		)	(77		)
Other, net	21			(3		)	(8		)
Total	(182		)	(200		)	(213		)
Income Before Income Taxes	436			425			424
Income tax expense (benefit)	80			89			(9		)
Net Income	$	356		$	336		$	433

See Combined Notes to Consolidated Financial Statements

113

CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC AND SUBSIDIARIES

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

STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME

	Year Ended December 31,
	2019			2018			2017
	(in millions)
Net income	$	356		$	336		$	433
Other comprehensive income (loss):
Net deferred loss from cash flow hedges (net of tax expense (benefit) of $-0-, ($4), and $-0-, respectively)	(1		)	(14		)	(1		)
Other comprehensive loss	(1		)	(14		)	(1		)
Comprehensive income	$	355		$	322		$	432

See Combined Notes to Consolidated Financial Statements

114

CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC AND SUBSIDIARIES

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

CONSOLIDATED BALANCE SHEETS

	December 31, 2019			December 31, 2018
	(in millions)
ASSETS
Current Assets:
Cash and cash equivalents ($216 and $335 related to VIEs, respectively)	$	216		$	335
Accounts and notes receivable, net ($26 and $56 related to VIEs, respectively), less bad debt reserve of $1 and $1, respectively	238			283
Accounts and notes receivable—affiliated companies	523			20
Accrued unbilled revenues	117			110
Materials and supplies	147			135
Taxes receivable	—			5
Prepaid expenses and other current assets ($19 and $34 related to VIEs, respectively)	49			61
Total current assets	1,290			949
Property, Plant and Equipment, net	9,032			8,402
Other Assets:
Regulatory assets ($788 and $1,059 related to VIEs, respectively)	915			1,124
Other	25			32
Total other assets	940			1,156
Total Assets	$	11,262		$	10,507
LIABILITIES AND MEMBER’S EQUITY
Current Liabilities:
Current portion of VIE Securitization Bonds long-term debt	$	231		$	458
Accounts payable	268			262
Accounts and notes payable—affiliated companies	76			78
Taxes accrued	123			115
Interest accrued	69			64
Non-trading derivative liabilities	—			24
Other	63			89
Total current liabilities	830			1,090
Other Liabilities:
Deferred income taxes, net	1,030			1,023
Benefit obligations	75			91
Regulatory liabilities	1,288			1,298
Other	69			65
Total other liabilities	2,462			2,477
Long-Term Debt, net:
VIE Securitization Bonds, net	746			977
Other long-term debt, net	3,973			3,281
Total long-term debt, net	4,719			4,258
Commitments and Contingencies (Note 16)
Member’s Equity:
Common stock	—			—
Additional paid-in capital	2,486			1,896
Retained earnings	780			800
Accumulated other comprehensive loss	(15		)	(14		)
Total member’s equity	3,251			2,682
Total Liabilities and Member’s Equity	$	11,262		$	10,507

See Combined Notes to Consolidated Financial Statements

115

CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC AND SUBSIDIARIES

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

STATEMENTS OF CONSOLIDATED CASH FLOWS

	Year Ended December 31,
	2019			2018			2017
	(in millions)
Cash Flows from Operating Activities:
Net income	$	356		$	336		$	433
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	648			917			724
Amortization of deferred financing costs	12			11			13
Deferred income taxes	(24		)	(38		)	(98		)
Changes in other assets and liabilities:
Accounts and notes receivable, net	38			11			(73		)
Accounts receivable/payable–affiliated companies	(23		)	20			(46		)
Inventory	(12		)	(16		)	15
Accounts payable	13			(1		)	59
Taxes receivable	5			(5		)	6
Interest and taxes accrued	13			(2		)	7
Non-trading derivatives, net	(25		)	5			—
Net regulatory assets and liabilities	(48		)	(97		)	(148		)
Other current assets	(5		)	(2		)	(6		)
Other current liabilities	(9		)	(26		)	16
Other assets	5			(3		)	13
Other liabilities	(12		)	17			(4		)
Other, net	(14		)	(12		)	(6		)
Net cash provided by operating activities	918			1,115			905
Cash Flows from Investing Activities:
Capital expenditures	(1,025		)	(922		)	(875		)
Decrease (increase) in notes receivable–affiliated companies	(481		)	—			96
Other, net	11			11			3
Net cash used in investing activities	(1,495		)	(911		)	(776		)
Cash Flows from Financing Activities:
Proceeds from long-term debt, net	696			398			298
Payments of long-term debt	(458		)	(434		)	(411		)
Dividend to parent	(376		)	(209		)	(180		)
Increase (decrease) in notes payable–affiliated companies	(1		)	(59		)	60
Debt issuance costs	(8		)	(4		)	(3		)
Contribution from parent	590			200			—
Other, net	(1		)	—			—
Net cash provided by (used in) financing activities	442			(108		)	(236		)
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	(135		)	96			(107		)
Cash, Cash Equivalents and Restricted Cash at Beginning of the Year	370			274			381
Cash, Cash Equivalents and Restricted Cash at End of the Year	$	235		$	370		$	274

See Combined Notes to Consolidated Financial Statements

116

CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC AND SUBSIDIARIES

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

STATEMENTS OF CONSOLIDATED CHANGES IN EQUITY

	2019				2018				2017
	Shares	Amount			Shares	Amount			Shares	Amount
	(in millions, except share amounts)
Common Stock
Balance, beginning of year	1,000	$	—		1,000	$	—		1,000	$	—
Balance, end of year	1,000	—			1,000	—			1,000	—
Additional Paid-in-Capital
Balance, beginning of year		1,896				1,696				1,696
Contribution from parent		590				200				—
Balance, end of year		2,486				1,896				1,696
Retained Earnings
Balance, beginning of year		800				673				420
Net income		356				336				433
Dividend to parent		(376		)		(209		)		(180		)
Balance, end of year		780				800				673
Accumulated Other Comprehensive Income (Loss)
Balance, beginning of year		(14		)		—				1
Other comprehensive loss		(1		)		(14		)		(1		)
Balance, end of year		(15		)		(14		)		—
Total Member’s Equity		$	3,251			$	2,682			$	2,369

See Combined Notes to Consolidated Financial Statements

117

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Stockholder of

CenterPoint Energy Resources Corp.

Houston, Texas

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of CenterPoint Energy Resources Corp. and subsidiaries (the “Company”, an indirect wholly owned subsidiary of CenterPoint Energy, Inc.) as of December 31, 2019 and 2018, the related statements of consolidated income, comprehensive income, changes in equity, and cash flows, for each of the three years in the period ended December 31, 2019, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas  

February 27, 2020  

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

118

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

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

STATEMENTS OF CONSOLIDATED INCOME

	Year Ended December 31,
	2019			2018			2017
	(in millions)
Revenues:
Utility revenues	$	2,911		$	2,931		$	2,606
Non-utility revenues	3,659			4,412			3,997
Total	6,570			7,343			6,603
Expenses:
Utility natural gas	1,312			1,410			1,109
Non-utility cost of revenue, including natural gas	3,503			4,364			3,785
Operation and maintenance	890			898			816
Depreciation and amortization	305			293			279
Taxes other than income taxes	162			156			147
Goodwill impairment	48			—			—
Total	6,220			7,121			6,136
Operating Income	350			222			467
Other Income (Expense):
Interest and other finance charges	(116		)	(122		)	(123		)
Other, net	(8		)	(8		)	(25		)
Total	(124		)	(130		)	(148		)
Income From Continuing Operations Before Income Taxes	226			92			319
Income tax expense (benefit)	14			22			(265		)
Income From Continuing Operations	212			70			584
Income from discontinued operations (net of tax expense of $-0-, $46, and $104, respectively)	—			138			161
Net Income	$	212		$	208		$	745

See Combined Notes to Consolidated Financial Statements

119

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

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

STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME

	Year Ended December 31,
	2019		2018			2017
	(in millions)
Net income	$	212	$	208		$	745
Other comprehensive income (loss):
Adjustment to postretirement plans (net of tax expense of $2, $1 and $4, respectively)	5		1			4
Net deferred loss from cash flow hedges (net of tax expense (benefit) of $-0-, $-0- and ($1), respectively)	—		(1		)	(1		)
Other comprehensive income	5		—			3
Comprehensive income	$	217	$	208		$	748

See Combined Notes to Consolidated Financial Statements

120

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

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

CONSOLIDATED BALANCE SHEETS

	December 31, 2019		December 31, 2018
	(in millions)
ASSETS
Current Assets:
Cash and cash equivalents	$	2	$	14
Accounts receivable, less bad debt reserve of $15 million and $17 million, respectively	693		894
Accrued unbilled revenue	257		268
Accounts and notes receivable — affiliated companies	10		120
Material and supplies	71		65
Natural gas inventory	202		194
Non-trading derivative assets	136		100
Prepaid expenses and other current assets	44		115
Total current assets	1,415		1,770
Property, Plant and Equipment, Net	5,836		5,226
Other Assets:
Goodwill	819		867
Regulatory assets	191		181
Non-trading derivative assets	58		38
Other	120		132
Total other assets	1,188		1,218
Total Assets	$	8,439	$	8,214

See Combined Notes to Consolidated Financial Statements

121

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

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

CONSOLIDATED BALANCE SHEETS, cont.

	December 31, 2019		December 31, 2018
	(in millions)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities:
Accounts payable	$	557	$	856
Accounts and notes payable–affiliated companies	48		50
Taxes accrued	84		82
Interest accrued	38		38
Customer deposits	76		75
Non-trading derivative liabilities	44		102
Other	191		137
Total current liabilities	1,038		1,340
Other Liabilities:
Deferred income taxes, net	470		406
Non-trading derivative liabilities	14		5
Benefit obligations	83		93
Regulatory liabilities	1,219		1,227
Other	428		329
Total other liabilities	2,214		2,060
Long-Term Debt	2,546		2,371
Commitments and Contingencies (Note 16)
Stockholder’s Equity:
Common stock	—		—
Additional paid-in capital	2,116		2,015
Retained earnings	515		423
Accumulated other comprehensive income	10		5
Total stockholder’s equity	2,641		2,443
Total Liabilities and Stockholder’s Equity	$	8,439	$	8,214

See Combined Notes to Consolidated Financial Statements

122

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

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

STATEMENTS OF CONSOLIDATED CASH FLOWS 

	Year Ended December 31,
	2019			2018			2017
	(in millions)
Cash Flows from Operating Activities:
Net income	$	212		$	208		$	745
Less: Income from discontinued operations, net of tax	—			138			161
Income from continuing operations	212			70			584
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	305			293			279
Amortization of deferred financing costs	9			9			9
Deferred income taxes	7			31			(224		)
Goodwill impairment	48			—			—
Write-down of natural gas inventory	4			2			—
Changes in other assets and liabilities:
Accounts receivable and unbilled revenues, net	252			(155		)	(143		)
Accounts receivable/payable–affiliated companies	(6		)	9			—
Inventory	(12		)	17			(22		)
Accounts payable	(305		)	163			64
Fuel cost recovery	86			33			(85		)
Interest and taxes accrued	2			—			(41		)
Non-trading derivatives, net	(60		)	98			(82		)
Margin deposits, net	(56		)	5			(55		)
Net regulatory assets and liabilities	(10		)	50			(27		)
Other current assets	1			4			2
Other current liabilities	22			(3		)	15
Other assets	5			5			(8		)
Other liabilities	(38		)	6			6
Other, net	—			1			6
Net cash provided by operating activities from continuing operations	466			638			278
Net cash provided by operating activities from discontinued operations	—			176			—
Net cash provided by operating activities	466			814			278
Cash Flows from Investing Activities:
Capital expenditures	(776		)	(633		)	(513		)
Acquisitions, net of cash acquired	—			—			(132		)
(Increase) decrease in notes receivable–affiliated companies	114			(114		)	—
Other, net	—			3			2
Net cash used in investing activities from continuing operations	(662		)	(744		)	(643		)
Net cash provided by investing activities from discontinued operations	—			47			297
Net cash used in investing activities	(662		)	(697		)	(346		)
Cash Flows from Financing Activities:
Increase (decrease) in short-term borrowings, net	—			(39		)	4
Proceeds from (payments of) commercial paper, net	167			(688		)	329
Proceeds from long-term debt	—			599			298
Payments of long-term debt	—			—			(550		)
Dividends to parent	(120		)	(360		)	(601		)
Debt issuance costs	—			(5		)	(4		)
Loss on reacquired debt	—			—			(5		)
Contribution from parent	129			960			38
Increase (decrease) in notes payable–affiliated companies	—			(570		)	570
Other, net	(3		)	(1		)	—
Net cash provided by (used in) financing activities from continuing operations	173			(104		)	79
Net cash provided by financing activities from discontinued operations	—			—			—
Net cash provided by (used in) financing activities	173			(104		)	79
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	(23		)	13			11
Cash, Cash Equivalents and Restricted Cash at Beginning of Year	25			12			1
Cash, Cash Equivalents and Restricted Cash at End of Year	$	2		$	25		$	12

See Combined Notes to Consolidated Financial Statements

123

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

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

STATEMENTS OF CONSOLIDATED CHANGES IN EQUITY

	2019				2018				2017
	Shares	Amount			Shares	Amount			Shares	Amount
	(in millions, except share amounts)
Common Stock
Balance, beginning of year	1,000	$	—		1,000	$	—		1,000	$	—
Balance, end of year	1,000	—			1,000	—			1,000	—
Additional Paid-in-Capital
Balance, beginning of year		2,015				2,528				2,489
Contribution from parent		129				960				38
Capital distribution to parent associated with Internal Spin		(28		)		(1,473		)		—
Other		—				—				1
Balance, end of year		2,116				2,015				2,528
Retained Earnings
Balance, beginning of year		423				574				430
Net income		212				208				745
Dividend to parent		(120		)		(360		)		(601		)
Adoption of ASU 2018-02		—				1				—
Balance, end of year		515				423				574
Accumulated Other Comprehensive Income
Balance, beginning of year		5				6				3
Other comprehensive income		5				—				3
Adoption of ASU 2018-02		—				(1		)		—
Balance, end of year		10				5				6
Total Stockholder’s Equity		$	2,641			$	2,443			$	3,108

See Combined Notes to Consolidated Financial Statements

124

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC AND SUBSIDIARIES

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) Background

General. This combined Form 10-K is filed separately by three registrants: CenterPoint Energy, Inc., CenterPoint Energy Houston Electric, LLC and CenterPoint Energy Resources Corp. Information contained herein relating to any individual registrant is filed by such registrant solely on its own behalf. Each registrant makes no representation as to information relating exclusively to the other Registrants or the subsidiaries of CenterPoint Energy other than itself or its subsidiaries.

Except as discussed in Note 14 to the Registrants’ Consolidated Financial Statements, no registrant has an obligation in respect of any other Registrant’s debt securities, and holders of such debt securities should not consider the financial resources or results of operations of any Registrant other than the obligor in making a decision with respect to such securities.

Included in this combined Form 10-K are the Financial Statements of CenterPoint Energy, Houston Electric and CERC, which are referred to collectively as the Registrants. The Combined Notes to the Consolidated Financial Statements apply to all Registrants and specific references to Houston Electric and CERC herein also pertain to CenterPoint Energy, unless otherwise indicated.

Background. CenterPoint Energy, Inc. is a public utility holding company and owns interests in Enable as described below. On the Merger Date, pursuant to the Merger Agreement, CenterPoint Energy consummated the previously announced Merger and acquired Vectren for approximately $6 billion in cash. On the Merger Date, Vectren became a wholly-owned subsidiary of CenterPoint Energy.

As of December 31, 2019, CenterPoint Energy’s operating subsidiaries were as follows:

• Houston Electric owns and operates electric transmission and distribution facilities in the Texas Gulf Coast area that includes the city of Houston; and

• CERC Corp. (i) owns and operates natural gas distribution systems in six states and (ii) obtains and offers competitive variable and fixed-price physical natural gas supplies and services primarily to commercial and industrial customers and electric and natural gas utilities in over 30 states through its wholly-owned subsidiary, CES.

• Vectren holds three public utilities through its wholly-owned subsidiary, VUHI, a public utility holding company:

• Indiana Gas provides energy delivery services to natural gas customers located in central and southern Indiana;

• SIGECO provides energy delivery services to electric and natural gas customers located near Evansville in southwestern Indiana and owns and operates electric generation assets to serve its electric customers and optimizes those assets in the wholesale power market; and

• VEDO provides energy delivery services to natural gas customers located near Dayton in west-central Ohio.

• Vectren performs non-utility activities through:

• Infrastructure Services, which provides underground pipeline construction and repair services through wholly-owned subsidiaries Miller Pipeline, LLC and Minnesota Limited, LLC and serves natural gas utilities across the United States, focusing on recurring integrity, station and maintenance work and opportunities for large transmission pipeline construction projects; and

• ESG, which provides energy performance contracting and sustainable infrastructure services, such as renewables, distributed generation and combined heat and power projects.

For a description of CenterPoint Energy’s and CERC’s reportable segments, see Note 19. Houston Electric consists of a single reportable segment, Houston Electric T&D.

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As of December 31, 2019, CenterPoint Energy, indirectly through CNP Midstream, owned approximately 53.7% of the common units representing limited partner interests in Enable, 50% of the management rights and 40% of the incentive distribution rights in Enable GP and also directly owned an aggregate of 14,520,000 Enable Series A Preferred Units. Enable owns, operates and develops natural gas and crude oil infrastructure assets.

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 is expected to close in the second quarter of 2020. For further information, see Notes 6 and 23.

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. The transaction is expected to close in the second quarter of 2020. For further information, see Notes 6 and 23.

(2) Summary of Significant Accounting Policies

(a) Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

(b) Principles of Consolidation

The accounts of the Registrants and their wholly-owned and majority-owned and controlled subsidiaries are included in the consolidated financial statements. All intercompany transactions and balances are eliminated in consolidation, except as described below.

Businesses within the Infrastructure Services reportable segment provide underground pipeline construction and repair services for customers that include NGD utilities. In accordance with consolidation guidance in ASC 980—Regulated Operations, costs incurred by NGD utilities for these pipeline construction and repair services are not eliminated in consolidation when capitalized and included in rate base by the NGD utility. Fees incurred by CenterPoint Energy’s and CERC’s NGD for pipeline construction and repair services that were capitalized totaled $162 million and $20 million, respectively, for the 11 months ended December 31, 2019.

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 is expected to close in the second quarter of 2020. For further information, see Notes 6 and 23.

As of December 31, 2019, CenterPoint Energy and Houston Electric had VIEs consisting of the Bond Companies, which are consolidated. The consolidated VIEs are wholly-owned, bankruptcy remote special purpose entities that were formed solely for the purpose of securitizing transition and system restoration related property. Creditors of CenterPoint Energy and Houston Electric have no recourse to any assets or revenues of the Bond Companies. The bonds issued by these VIEs are payable only from and secured by transition and system restoration property and the bondholders have no recourse to the general credit of CenterPoint Energy or Houston Electric.

(c) Equity and Investments without a Readily Determinable Fair Value (CenterPoint Energy)

CenterPoint Energy generally uses the equity method of accounting for investments in entities in which it has an ownership interest between 20% and 50% and exercises significant influence. CenterPoint Energy also uses the equity method for investments in which it has ownership percentages greater than 50%, when it exercises significant influence, does not have control and is not considered the primary beneficiary, if applicable.

Under the equity method, CenterPoint Energy adjusts its investments each period for contributions made, distributions received, respective shares of comprehensive income and amortization of basis differences, as appropriate. CenterPoint Energy evaluates its equity method investments for impairment when events or changes in circumstances indicate there is a loss in value of the investment that is other than a temporary decline.

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CenterPoint Energy considers distributions received from equity method investments which do not exceed cumulative equity in earnings subsequent to the date of investment to be a return on investment and classifies these distributions as operating activities in its Statements of Consolidated Cash Flows. CenterPoint Energy considers distributions received from equity method investments in excess of cumulative equity in earnings subsequent to the date of investment to be a return of investment and classifies these distributions as investing activities in its Statements of Consolidated Cash Flows.

Investments without a readily determinable fair value will be measured at cost, less impairment, plus or minus observable prices changes of an identical or similar investment of the same issuer.

(d) Revenues

The Registrants record revenue for electricity delivery and natural gas sales and services under the accrual method and these revenues are recognized upon delivery to customers. Electricity deliveries not billed by month-end are accrued based on actual AMS data, daily supply volumes and applicable rates. Natural gas sales not billed by month-end are accrued based upon estimated purchased gas volumes, estimated lost and unaccounted for gas and currently effective tariff rates. Revenue for some pipeline construction services are based on the percentage of completion method. For further discussion, see Note 5.

(e) MISO Transactions

Indiana Electric is a member of the MISO. MISO-related purchase and sale transactions are recorded using settlement information provided by the MISO. These purchase and sale transactions are accounted for on at least a net hourly position, meaning net purchases within that interval are recorded on CenterPoint Energy’s Statements of Consolidated Income in Utility natural gas, fuel and purchased power, and net sales within that interval are recorded on CenterPoint Energy’s Statements of Consolidated Income in Utility revenues. On occasion, prior period transactions are resettled outside the routine process due to a change in the MISO’s tariff or a material interpretation thereof. Expenses associated with resettlements are recorded once the resettlement is probable and the resettlement amount can be estimated. Revenues associated with resettlements are recognized when the amount is determinable and collectability is reasonably assured.

(f) Guarantees

CenterPoint Energy recognizes guarantee obligations at fair value. CenterPoint Energy discloses parent company guarantees of a subsidiary’s obligation when that guarantee results in the exposure of a material obligation of the parent company even if the probability of fulfilling such obligation is considered remote. See Note 16(c) and (d).  

(g) Long-lived Assets, Goodwill and Intangibles

The Registrants record property, plant and equipment at historical cost and expense repair and maintenance costs as incurred.

The Registrants periodically evaluate long-lived assets, including property, plant and equipment, and specifically identifiable intangibles subject to amortization, when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable. For rate regulated businesses, recoverability of long-lived assets is assessed by determining if a capital disallowance from a regulator is probable through monitoring the outcome of rate cases and other proceedings. For non-rate regulated businesses, recoverability is assessed based on an estimate of undiscounted cash flows attributable to the assets compared to the carrying value of the assets. As of December 31, 2019, CenterPoint Energy and CERC, as applicable, determined that the carrying value of long-lived and intangible assets associated with the Infrastructure Services and Energy Services reporting units were recoverable based on undiscounted cash flows, considering the likelihood of possible outcomes existing as of that date, including the assessment of the likelihood of a future sale of these assets. No long-lived asset or intangible asset impairments were recorded in 2019, 2018 or 2017.

CenterPoint Energy and CERC perform goodwill impairment tests at least annually and evaluate goodwill when events or changes in circumstances indicate that its carrying value may not be recoverable. Subsequent to the Registrant’s adoption of ASU 2017-04 Simplifying the Test for Goodwill Impairment on January 1, 2018, CenterPoint Energy and CERC recognize a goodwill impairment by the amount a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill within that reporting unit. CenterPoint Energy includes deferred tax assets and liabilities within its reporting unit’s carrying value for the purposes of annual and interim impairment tests, regardless of whether the estimated fair value reflects the disposition of such assets and liabilities. For further information about the goodwill impairment tests during 2019, see Note 6.

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(h) Assets Held for Sale and Discontinued Operations

Generally, a long-lived asset to be sold is classified as held for sale in the period in which management, with approval from the Board of Directors, as applicable, commits to a plan to sell and a sale is expected to be completed within one year. The Registrants record assets and liabilities held for sale at the lower of their carrying value or their estimated fair value less cost to sell. If the disposal group reflects a component of a reporting unit and meets the definition of a business, the goodwill within that reporting unit is allocated to the disposal group based on the relative fair value of the components representing a business that will be retained and disposed. Goodwill is not allocated to a portion of a reporting unit that does not meet the definition of a business. A disposal group that meets the held for sale criteria and also represents a strategic shift to the Registrant, is also reflected as discontinued operations on the Statements of Consolidated Income, and prior periods are recast to reflect the earnings or losses from such businesses as income from discontinued operations, net of tax.

(i) Regulatory Assets and Liabilities

The Registrants apply the guidance for accounting for regulated operations to the Houston Electric T&D reportable segment, Indiana Electric Integrated segment and the Natural Gas Distribution reportable segment. The Registrants’ rate-regulated subsidiaries may collect revenues subject to refund pending final determination in rate proceedings. In connection with such revenues, estimated rate refund liabilities are recorded which reflect management’s current judgment of the ultimate outcomes of the proceedings.

The Registrants’ rate-regulated businesses recognize removal costs as a component of depreciation expense in accordance with regulatory treatment. In addition, a portion of the amount of removal costs collected from customers that relate to AROs has been reflected as an asset retirement liability in accordance with accounting guidance for AROs.

For further detail on the Registrants’ regulatory assets and liabilities, see Note 7.

(j) Depreciation and Amortization Expense

The Registrants compute depreciation and amortization using the straight-line method based on economic lives or regulatory-mandated recovery periods. Amortization expense includes amortization of certain regulatory assets and other intangibles.

(k) Capitalization of Interest and AFUDC

The Registrants capitalize interest and AFUDC as a component of projects under construction and amortize it over the assets’ estimated useful lives once the assets are placed in service. AFUDC represents the composite interest cost of borrowed funds and a reasonable return on the equity funds used for construction for subsidiaries that apply the guidance for accounting for regulated operations. Although AFUDC increases both utility plant and earnings, it is realized in cash when the assets are included in rates.

	Year Ended December 31,
	2019						2018						2017
	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC
	(in millions)
Interest and AFUDC debt (1)	$	36	$	8	$	3	$	8	$	6	$	2	$	9	$	6	$	2
AFUDC equity (2)	22		15		3		12		10		2		11		10		1

(1) Included in Interest and other finance charges on the Registrants’ respective Statements of Consolidated Income.

(2) Included in Other Income (Expense) on the Registrants’ respective Statements of Consolidated Income.

(l) Income Taxes

Houston Electric and CERC are included in CenterPoint Energy’s U.S. federal consolidated income tax return. Houston Electric and CERC report their income tax provision on a separate entity basis pursuant to a tax sharing agreement with CenterPoint Energy. Current federal and certain state income taxes are payable to or receivable from CenterPoint Energy.

The Registrants use the asset and liability method of accounting for deferred income taxes. Deferred income tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. A valuation allowance is established against deferred tax

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assets for which management believes realization is not considered to be more likely than not. The Registrants recognize interest and penalties as a component of income tax expense (benefit), as applicable, in their respective Statements of Consolidated Income. CenterPoint Energy reports the income tax provision associated with its interest in Enable in income tax expense (benefit) in its Statements of Consolidated Income.

On December 22, 2017, President Trump signed into law comprehensive tax reform legislation informally called the Tax Cuts and Jobs Acts, or TCJA, which resulted in significant changes to federal tax laws effective January 1, 2018. See Note 15 for further discussion of the impacts of tax reform implementation.

To the extent certain EDIT of the Registrants’ rate-regulated subsidiaries may be recoverable or payable through future rates, regulatory assets and liabilities have been recorded, respectively.

The Registrants use the portfolio approach to recognize income tax effects on other comprehensive income from accumulated other comprehensive income.

Investment tax credits are deferred and amortized to income over the approximate lives of the related property.

(m) Accounts Receivable and Allowance for Doubtful Accounts

Accounts receivable are recorded at the invoiced amount and do not bear interest. Management reviews the outstanding accounts receivable, as well as the bad debt write-offs experienced in the past, and establishes an allowance for doubtful accounts. Account balances are charged off against the allowance when management determines it is probable the receivable will not be recovered.

The table below summarizes the Registrants’ provision for doubtful accounts for 2019, 2018 and 2017:

	Year Ended December 31,
	2019						2018						2017
	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC
	(in millions)
Provision for doubtful accounts	$	16	$	—	$	12	$	16	$	—	$	16	$	14	$	1	$	13

(n) Inventory

The Registrants’ inventory consists principally of materials and supplies, and for CERC, natural gas, and for CenterPoint Energy, coal inventory. Materials and supplies are valued at the lower of average cost or market. Materials and supplies are recorded to inventory when purchased and subsequently charged to expense or capitalized to plant when installed. Natural gas inventories of CERC’s Energy Services reportable segment at locations qualifying for and utilizing the fair value hedge accounting election are valued at fair value; inventories at locations not qualifying for or not utilizing the fair value hedge accounting election are valued at the lower of average cost or market. During 2019, 2018 and 2017, CERC recorded write-downs of natural gas inventory to the lower of average cost or market which are disclosed on the respective Statements of Consolidated Cash Flows.

(o) Derivative Instruments

The Registrants are exposed to various market risks. These risks arise from transactions entered into in the normal course of business. The Registrants utilize derivative instruments such as physical forward contracts, swaps and options to mitigate the impact of changes in commodity prices, weather and interest rates on operating results and cash flows. Such derivatives are recognized in the Registrants’ Consolidated Balance Sheets at their fair value unless the Registrant elects the normal purchase and sales exemption for qualified physical transactions. A derivative may be designated as a normal purchase or normal sale if the intent is to physically receive or deliver the product for use or sale in the normal course of business. CenterPoint Energy and CERC have elected to record changes in the fair value of amounts excluded from the assessment of effectiveness immediately in their Statements of Consolidated Income.

CenterPoint Energy has a Risk Oversight Committee composed of corporate and reportable segment officers that oversees commodity price, weather and credit risk activities, including the Registrants’ marketing, risk management services and hedging activities. The committee’s duties are to establish the Registrants’ commodity risk policies, allocate board-approved commercial risk limits, approve the use of new products and commodities, monitor positions and ensure compliance with the Registrants’ risk

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management policies and procedures and limits established by CenterPoint Energy’s Board of Directors. The Registrants’ policies prohibit the use of leveraged financial instruments. A leveraged financial instrument, for this purpose, is a transaction involving a derivative whose financial impact will be based on an amount other than the notional amount or volume of the instrument.

(p) Investments in Equity Securities (CenterPoint Energy and CERC)

CenterPoint Energy and CERC report equity securities at estimated fair value in their respective Consolidated Balance Sheets, and any unrealized holding gains and losses are recorded as Other Income (Expense) in their respective Statements of Consolidated Income.

(q) Environmental Costs

The Registrants expense or capitalize environmental expenditures, as appropriate, depending on their future economic benefit. The Registrants expense amounts that relate to an existing condition caused by past operations that do not have future economic benefit. The Registrants record undiscounted liabilities related to these future costs when environmental assessments and/or remediation activities are probable and the costs can be reasonably estimated.

(r) Cash and Cash Equivalents and Restricted Cash

For purposes of reporting cash flows, the Registrants consider cash equivalents to be short-term, highly-liquid investments with maturities of three months or less from the date of purchase. Cash and cash equivalents held by the Bond Companies (VIEs) solely to support servicing the Securitization Bonds as of December 31, 2019 and 2018 are reflected on CenterPoint Energy’s and Houston Electric’s Consolidated Balance Sheets.

In connection with the issuance of Securitization Bonds, CenterPoint Energy and Houston Electric were required to establish restricted cash accounts to collateralize the bonds that were issued in these financing transactions. These restricted cash accounts are not available for withdrawal until the maturity of the bonds and are not included in cash and cash equivalents. For more information on restricted cash see Note 20.

(s) Preferred Stock and Dividends

Preferred stock is evaluated to determine balance sheet classification, and all conversion and redemption features are evaluated for bifurcation treatment. Proceeds received net of issuance costs are recognized on the settlement date. Cash dividends become a liability once declared. Income available to common stockholders is computed by deducting from net income the dividends accumulated and earned during the period on cumulative preferred stock.

(t) Purchase Accounting

The Registrants evaluate acquisitions to determine when a set of acquired activities and assets represent a business. When control of a business is obtained, the Registrants apply the acquisition method of accounting and record the assets acquired, liabilities assumed and any non-controlling interest obtained based on fair value at the acquisition date. The excess of the fair value of purchase consideration over the fair value of the net assets acquired is recorded as goodwill. The results of operations of the acquired business are included in the Registrants’ respective Statements of Consolidated Income beginning on the date of the acquisition.

(u) New Accounting Pronouncements

The following table provides an overview of certain recently adopted or issued accounting pronouncements applicable to all the Registrants, unless otherwise noted.

Recently Adopted Accounting Standards
ASU Number and Name	Description	Date of Adoption	Financial Statement Impact upon Adoption
ASU 2016-02- Leases (Topic 842) and related amendments	ASU 2016-02 provides a comprehensive new lease model that requires lessees to recognize assets and liabilities for most leases and would change certain aspects of lessor accounting. Transition method: modified retrospective	January 1, 2019	The Registrants adopted the standard and recognized a right-of-use asset and lease liability on their statement of financial position with no material impact on their results of operations and cash flows. See Note 22 for more information.

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Issued, Not Yet Effective Accounting Standards
ASU Number and Name	Description	Effective Date	Financial Statement Impact upon Adoption
ASU 2016-13- Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments	This standard, including standards amending this standard, requires a new model called CECL to estimate credit losses for (1) financial assets subject to credit losses and measured at amortized cost and (2) certain off-balance sheet credit exposures. Upon initial recognition of the exposure, the CECL model requires an entity to estimate the credit losses expected over the life of an exposure based on historical information, current information and reasonable and supportable forecasts, including estimates of prepayments. Transition method: modified retrospective	January 1, 2020 Early adoption is permitted	The adoption of this standard will result in an immaterial adjustment to the carrying value of the Registrants’ accounts receivable, net. The adoption of this standard will not have a material impact on the Registrants’ financial position, results of operations or cash flows.
ASU 2018-13- Fair Value Measurement (Topic 820): Disclosure Framework-Changes to the Disclosure Requirements for Fair Value Measurement	This standard eliminates, modifies and adds certain disclosure requirements for fair value measurements. Transition method: prospective for additions and one modification and retrospective for all other amendments	Adoption of eliminations and modifications as of September 30, 2018; Additions will be adopted January 1, 2020	The adoption of this standard did not impact the Registrants’ financial position, results of operations or cash flows. Note 10 reflects the disclosures modified upon adoption.
ASU 2018-15-Intangibles-Goodwill and Other- Internal-Use Software (Subtopic 350-40): Customer's Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract	This standard aligns accounting for implementation costs incurred in a cloud computing arrangement that is accounted for as a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. The update also prescribes the balance sheet, income statement and cash flow classification of the capitalized implementation costs and related amortization expense and requires additional quantitative and qualitative disclosures. Transition method: retrospective or prospective	January 1, 2020 Early adoption is permitted	The adoption of this standard will require the Registrants to capitalize certain costs to implement cloud computing arrangements that are accounted for as service contracts within Prepaid expenses and other current assets on the Registrants’ consolidated balance sheets and record the amortization of such assets within Operation and maintenance expenses on the Registrants’ statements of consolidated income. The adoption of this standard will not have a material impact on the Registrants’ financial position, results of operations, cash flows or disclosures.

Management believes that other recently adopted standards and recently issued standards that are not yet effective will not have a material impact on the Registrants’ financial position, results of operations or cash flows upon adoption.

(3) Property, Plant and Equipment

(a) Property, Plant and Equipment

Property, plant and equipment includes the following:

		December 31, 2019						December 31, 2018
	Weighted Average Useful Lives	Property, Plant and Equipment, Gross		Accumulated Depreciation & Amortization		Property, Plant and Equipment, Net		Property, Plant and Equipment, Gross		Accumulated Depreciation & Amortization		Property, Plant and Equipment, Net
	(in years)	(in millions)
CenterPoint Energy
Electric Transmission & Distribution	37	$	14,360	$	4,634	$	9,726	$	12,148	$	3,746	$	8,402
Electric Generation (1)	27	1,780		698		1,082		—		—		—
Natural Gas Distribution	29	12,695		3,731		8,964		7,257		2,128		5,129
Energy Services (2)	27	136		53		83		121		43		78
Infrastructure Services (3)	10	317		22		295		—		—		—
Other property	19	1,397		602		795		741		306		435
Total		$	30,685	$	9,740	$	20,945	$	20,267	$	6,223	$	14,044
Houston Electric
Electric Transmission	46	$	3,358	$	674	$	2,684	$	3,077	$	650	$	2,427
Electric Distribution	35	7,876		2,586		5,290		7,524		2,553		4,971
Other transmission & distribution property	19	1,595		537		1,058		1,547		543		1,004
Total		$	12,829	$	3,797	$	9,032	$	12,148	$	3,746	$	8,402

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		December 31, 2019						December 31, 2018
	Weighted Average Useful Lives	Property, Plant and Equipment, Gross		Accumulated Depreciation & Amortization		Property, Plant and Equipment, Net		Property, Plant and Equipment, Gross		Accumulated Depreciation & Amortization		Property, Plant and Equipment, Net
	(in years)	(in millions)
CERC
Natural Gas Distribution	29	$	7,933	$	2,208	$	5,725	$	7,257	$	2,128	$	5,129
Energy Services (2)	27	136		53		83		121		43		78
Other property	16	55		27		28		53		34		19
Total		$	8,124	$	2,288	$	5,836	$	7,431	$	2,205	$	5,226

(1) SIGECO and AGC own a 300 MW unit at the Warrick Power Plant (Warrick Unit 4) as tenants in common. SIGECO’s share of the cost of this unit as of December 31, 2019, is $194 million with accumulated depreciation totaling $137 million. AGC and SIGECO share equally in the cost of operation and output of the unit. SIGECO’s share of operating costs is included in Operation and maintenance expense in CenterPoint Energy’s Statements of Consolidated Income.

(2) 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. The transaction is expected to close in the second quarter of 2020. For further information, see Notes 6 and 23.

(3) 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 is expected to close in the second quarter of 2020. For further information, see Notes 6 and 23.

(b) Depreciation and Amortization

The following table presents depreciation and amortization expense for 2019, 2018 and 2017:

	Year Ended December 31,
	2019						2018						2017
	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC
	(in millions)
Depreciation	$	920	$	339	$	281	$	626	$	342	$	264	$	619	$	354	$	243
Amortization of securitized regulatory assets	271		271		—		531		531		—		329		329		—
Other amortization	96		38		24		86		44		29		88		41		36
Total	$	1,287	$	648	$	305	$	1,243	$	917	$	293	$	1,036	$	724	$	279

(c) AROs

The Registrants recorded AROs associated with the removal of asbestos and asbestos-containing material in its buildings, including substation building structures. CenterPoint Energy recorded AROs relating to the closure of the ash ponds at A.B. Brown and F.B. Culley. CenterPoint Energy and Houston Electric also recorded AROs relating to treated wood poles for electric distribution, distribution transformers containing PCB (also known as Polychlorinated Biphenyl), and underground fuel storage tanks. CenterPoint Energy and CERC also recorded AROs relating to gas pipelines abandoned in place. The estimates of future liabilities were developed using historical information, and where available, quoted prices from outside contractors.

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A reconciliation of the changes in the ARO liability recorded in Other non-current liabilities on each of the Registrants’ respective Consolidated Balance Sheets is as follows:

	December 31, 2019						December 31, 2018
	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy			Houston Electric			CERC
	(in millions)
Beginning balance	$	258	$	34	$	221	$	281		$	35		$	243
Addition from Merger with Vectren	116		—		—		—			—			—
Accretion expense (1)	16		1		10		10			1			9
Revisions in estimates (2)	149		7		94		(33		)	(2		)	(31		)
Ending balance	$	539	$	42	$	325	$	258		$	34		$	221

(1) Reflected in Regulatory assets on each of the Registrants’ respective Consolidated Balance Sheets.

(2) In 2019, the Registrants reflected an increase in their respective ARO liability, which is primarily attributable to decreases in the long-term interest rates used for discounting in the ARO calculation and increased estimated closure costs for CenterPoint Energy’s electric generation. In 2018, CenterPoint Energy and CERC reflected a decrease in their respective ARO liability, which is primarily attributable to increases in the long-term interest rates used for discounting in the ARO calculation.

(4) Mergers and Acquisitions (CenterPoint Energy)

Merger with Vectren. On the Merger Date, pursuant to the Merger Agreement, CenterPoint Energy consummated the previously announced Merger and acquired Vectren for approximately $6 billion in cash. Each share of Vectren common stock issued and outstanding immediately prior to the closing was canceled and converted into the right to receive $72.00 in cash per share, without interest. At the closing, each stock unit payable in Vectren common stock or whose value is determined with reference to the value of Vectren common stock, whether vested or unvested, was canceled with cash consideration paid in accordance with the terms of the Merger Agreement. These amounts did not include a stub period cash dividend of $0.41145 per share, which was declared, with CenterPoint Energy’s consent, by Vectren’s board of directors on January 16, 2019, and paid to Vectren stockholders as of the record date of February 1, 2019.

Pursuant to the Merger Agreement and immediately subsequent to the close of the Merger, CenterPoint Energy cash settled $78 million in outstanding share-based awards issued prior to the Merger Date by Vectren to its employees. As a result of the Merger, CenterPoint Energy assumed a liability for these share-based awards of $41 million and recorded an incremental cost of $37 million in Operation and maintenance expenses on its Statements of Consolidated Income during the year ended December 31, 2019 for the accelerated vesting of the awards in accordance with the Merger Agreement.

Subsequent to the close of the Merger, CenterPoint Energy recognized severance totaling $61 million to employees terminated immediately subsequent to the Merger close, inclusive of change of control severance payments to executives of Vectren under existing agreements, and which is included in Operation and maintenance expenses on its Statements of Consolidated Income during the year ended December 31, 2019. Total severance cost for the year ended December 31, 2019 was $102 million.

In connection with the Merger, VUHI and VCC made offers to prepay certain outstanding guaranteed senior notes as required pursuant to certain note purchase agreements previously entered into by VUHI and VCC. See Note 14 for further details.

Following the closing, shares of Vectren common stock, which previously traded under the ticker symbol “VVC” on the NYSE, ceased trading on and were delisted from the NYSE.

The Merger is being accounted for in accordance with ASC 805, Business Combinations, with CenterPoint Energy as the accounting acquirer of Vectren. Identifiable assets acquired and liabilities assumed have been recorded at their estimated fair values on the Merger Date.

Vectren’s regulated operations, comprised of electric generation and electric and natural gas energy delivery services, are subject to the rate-setting authority of the FERC, the IURC and the PUCO, and are accounted for pursuant to U.S. generally accepted accounting principles for regulated operations. The rate-setting and cost-recovery provisions currently in place for Vectren’s regulated operations provide revenues derived from costs including a return on investment of assets and liabilities included in rate base. Thus, the fair value of Vectren’s tangible and intangible assets and liabilities subject to these rate-setting

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provisions approximate their carrying values on the Merger Date.  The fair value of regulatory assets not earning a return have been determined using the income approach and are considered Level 3 fair value measurements due to the use of significant judgmental and unobservable inputs.

The fair value of Vectren’s assets acquired and liabilities assumed that are not subject to the rate-setting provisions, including identifiable intangibles, have been determined using the income approach and the market approach. The valuation of Vectren’s long-term debt is primarily considered a Level 2 fair value measurement. All other valuations are considered Level 3 fair value measurements due to the use of significant judgmental and unobservable inputs, including projected timing and amount of future cash flows and discount rates reflecting risk inherent in the future market prices.

The following table presents the purchase price allocation as of December 31, 2019 (in millions):

Cash and cash equivalents	$	16
Other current assets	577
Property, plant and equipment, net	5,147
Identifiable intangibles	297
Regulatory assets	338
Other assets	141
Total assets acquired	6,516
Current liabilities	648
Regulatory liabilities	938
Other liabilities	886
Long-term debt	2,401
Total liabilities assumed	4,873
Net assets acquired	1,643
Goodwill	4,339
Total purchase price consideration	$	5,982

CenterPoint Energy completed a final valuation analysis necessary to determine the fair market values of all of Vectren’s assets and liabilities and the allocation of its purchase price. Changes from the preliminary purchase price allocation originally reported in the first quarter of 2019 primarily included additional information obtained related to intangible assets and the allocation of the fair value between reporting units.

The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed is recognized as goodwill, which is primarily attributable to significant potential strategic benefits to CenterPoint Energy, including growth opportunities for more rate-regulated investment, more customers for existing products and services and additional products and services for existing customers. Additionally, CenterPoint Energy believes the Merger will increase geographic and business diversity as well as scale in attractive jurisdictions and economies. The value assigned to goodwill will not be deductible for tax purposes.

The fair value of the identifiable intangible assets and related useful lives as included in the purchase price allocation as of December 31, 2019 include:

	Weighted Average Useful Lives	Estimated Fair Value
	(in years)	(in millions)
Operation and maintenance agreements	24	$	12
Customer relationships	18	200
Construction backlog	1	27
Trade names	10	58
Total		$	297

Amortization expense related to the operation and maintenance agreements and construction backlog was $24 million in 2019, and is included in Non-utility cost of revenues, including natural gas on CenterPoint Energy’s Statements of Consolidated Income.

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Amortization expense related to customer relationships and trade names was $16 million in 2019 and is included in Depreciation and amortization expense on CenterPoint Energy’s Statements of Consolidated Income.

The results of operations for Vectren included in CenterPoint Energy’s Consolidated Financial Statements from the Merger Date for the year ended December 31, 2019 are as follows:

	(in millions)
Operating revenues	$	2,729
Net income	190

The following unaudited pro forma financial information reflects the consolidated results of operations of CenterPoint Energy, assuming the Merger had taken place on January 1, 2018. The unaudited pro forma financial information has been presented for illustrative purposes only and is not necessarily indicative of the consolidated results of operations that would have been achieved had the Merger taken place on the dates indicated or of the future consolidated results of operations of the combined company.

	Year Ended December 31,
	2019			2018
	(in millions)
Operating revenues	$	12,547		$	13,282
Net income	812		(1)	458		(2)

(1) Pro forma net income was adjusted to exclude $37 million of Vectren Merger-related transaction costs incurred in 2019.

(2) Pro forma net income was adjusted to include $37 million of Vectren Merger-related transaction costs incurred in 2019.

CenterPoint Energy incurred integration costs in connection with the Merger of $83 million for the year ended December 31, 2019, which were included in Operation and maintenance expenses in CenterPoint Energy’s Statements of Consolidated Income.

Acquisition of Utility Pipeline Construction Company. An acquisition was made during the year ended December 31, 2019 by CenterPoint Energy’s Infrastructure Services reportable segment, resulting in goodwill and intangible assets of approximately $6 million and $8 million, respectively. The intangible assets primarily relate to backlog and customer relationships. The allocation of the $25 million purchase price has been finalized. The results of operations for the acquired company have been included in CenterPoint Energy’s consolidated financial statements from the date of acquisition and are not significant to the consolidated financial results of CenterPoint Energy. Pro forma results of operations have not been presented for the acquisition because the effects of the acquisition were not significant to CenterPoint Energy’s consolidated financial results for all periods presented.

(5) Revenue Recognition

The Registrants adopted ASC 606, Revenue from Contracts with Customers, and all related amendments on January 1, 2018 using the modified retrospective method for those contracts that were not completed as of the date of adoption. Application of the new revenue standard did not result in a cumulative effect adjustment to the opening balance of retained earnings. The comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods. The adoption of the new standard did not have a material impact on the Registrants’ financial position, results of operations or cash flows.

In accordance with ASC 606, revenue is recognized when a customer obtains control of promised goods or services. The amount of revenue recognized reflects the consideration to which the Registrants expect to be entitled to receive in exchange for these goods or services.

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The following tables disaggregate revenues by reportable segment and major source:

CenterPoint Energy

	Year Ended December 31, 2019
	Houston Electric T&D (1)			Indiana Electric Integrated (1) (4)		Natural Gas Distribution (1) (4)			Energy  Services (2)			Infrastructure Services (2) (4)			Corporate and Other (2) (4)		Total
	(in millions)
Revenue from contracts	$	2,984		$	523	$	3,680		$	479		$	1,190		$	295	$	9,151
Derivatives income	6			—		2			3,303			—			—		3,311
Other (3)	6			—		1			—			—			5		12
Eliminations	—			—		(40		)	(129		)	(4		)	—		(173		)
Total revenues	$	2,996		$	523	$	3,643		$	3,653		$	1,186		$	300	$	12,301
	Year Ended December 31, 2018
	Houston Electric T&D (1)			Indiana Electric Integrated (1)		Natural Gas Distribution (1)			Energy  Services (2)			Infrastructure Services (2)			Corporate and Other (2)		Total
	(in millions)
Revenue from contracts	$	3,235		$	—	$	3,011		$	493		$	—		$	6	$	6,745
Derivatives income	(2		)	—		(2		)	4,028			—			—		4,024
Other (3)	(1		)	—		(42		)	—			—			9		(34		)
Eliminations	—			—		(36		)	(110		)	—			—		(146		)
Total revenues	$	3,232		$	—	$	2,931		$	4,411		$	—		$	15	$	10,589
	Year Ended December 31, 2017
	Houston Electric T&D (1)			Indiana Electric Integrated (1)		Natural Gas Distribution (1)			Energy Services (2)			Infrastructure Services (2)			Corporate and Other (2)		Total
	(in millions)
Revenue from contracts	$	3,001		$	—	$	2,638		$	480		$	—		$	5	$	6,124
Derivatives income	(1		)	—		—			3,569			—			—		3,568
Other (3)	(3		)	—		1			—			—			9		7
Eliminations	—			—		(33		)	(52		)	—			—		(85		)
Total revenues	$	2,997		$	—	$	2,606		$	3,997		$	—		$	14	$	9,614

(1) Reflected in Utility revenues in the Statements of Consolidated Income.

(2) Reflected in Non-utility revenues in the Statements of Consolidated Income.

(3) Primarily consists of income from ARPs and leases. ARPs are contracts between the utility and its regulators, not between the utility and a customer. The Registrants recognize ARP revenue as other revenues when the regulator-specified conditions for recognition have been met. Upon recovery of ARP revenue through incorporation in rates charged for utility service to customers, ARP revenue is reversed and recorded as revenue from contracts with customers. The recognition of ARP revenues and the reversal of ARP revenues upon recovery through rates charged for utility service may not occur in the same period.

(4) Reflects revenues from Vectren subsidiaries for the period from February 1, 2019 to December 31, 2019.

Houston Electric

	Year Ended December 31,
	2019		2018			2017
	(in millions)
Revenue from contracts	$	2,984	$	3,235		$	3,001
Other (1)	6		(1		)	(3		)
Total revenues	$	2,990	$	3,234		$	2,998

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(1) Primarily consists of income from ARPs and leases. ARPs are contracts between the utility and its regulators, not between the utility and a customer. The Registrants recognize ARP revenue as other revenues when the regulator-specified conditions for recognition have been met. Upon recovery of ARP revenue through incorporation in rates charged for utility service to customers, ARP revenue is reversed and recorded as revenue from contracts with customers. The recognition of ARP revenues and the reversal of ARP revenues upon recovery through rates charged for utility service may not occur in the same period.

CERC

	Year Ended December 31, 2019
	Natural Gas Distribution (1)			Energy  Services (2)			Corporate  and Other (2)		Total
	(in millions)
Revenue from contracts	$	2,945		$	480		$	5	$	3,430
Derivatives income	2			3,302			—		3,304
Other (3)	4			—			—		4
Eliminations	(40		)	(128		)	—		(168		)
Total revenues	$	2,911		$	3,654		$	5	$	6,570
	Year Ended December 31, 2018
	Natural Gas Distribution (1)			Energy  Services (2)			Corporate and Other (2)		Total
	(in millions)
Revenue from contracts	$	3,011		$	493		$	1	$	3,505
Derivatives income	(2		)	4,028			—		4,026
Other (3)	(42		)	—			—		(42		)
Eliminations	(36		)	(110		)	—		(146		)
Total revenues	$	2,931		$	4,411		$	1	$	7,343
	Year Ended December 31, 2017
	Natural Gas Distribution (1)			Energy  Services (2)			Corporate and Other (2)		Total
	(in millions)
Revenue from contracts	$	2,638		$	480		$	—	$	3,118
Derivatives income	—			3,569			—		3,569
Other (3)	1			—			—		1
Eliminations	(33		)	(52		)	—		(85		)
Total revenues	$	2,606		$	3,997		$	—	$	6,603

(1) Reflected in Utility revenues in the Statements of Consolidated Income.

(2) Reflected in Non-utility revenues in the Statements of Consolidated Income.

(3) Primarily consists of income from ARPs and leases. ARPs are contracts between the utility and its regulators, not between the utility and a customer. The Registrants recognize ARP revenue as other revenues when the regulator-specified conditions for recognition have been met. Upon recovery of ARP revenue through incorporation in rates charged for utility service to customers, ARP revenue is reversed and recorded as revenue from contracts with customers. The recognition of ARP revenues and the reversal of ARP revenues upon recovery through rates charged for utility service may not occur in the same period.

Revenues from Contracts with Customers

Houston Electric T&D (CenterPoint Energy and Houston Electric). Houston Electric distributes electricity to customers over time and customers consume the electricity when delivered. Revenue, consisting of both volumetric and fixed tariff rates set by the PUCT, is recognized as electricity is delivered and represents amounts both billed and unbilled. Discretionary services

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requested by customers are provided at a point in time with control transferring upon the completion of the service. Revenue for discretionary services is recognized upon completion of service based on the tariff rates set by the PUCT. Payments for electricity distribution and discretionary services are aggregated and received on a monthly basis. Houston Electric performs transmission services over time as a stand-ready obligation to provide a reliable network of transmission systems. Revenue is recognized upon time elapsed, and the monthly tariff rate set by the PUCT. Payments are received on a monthly basis.

Indiana Electric Integrated (CenterPoint Energy). Indiana Electric generates, distributes and transmits electricity to customers over time, and customers consume the electricity when delivered. Revenue, consisting of both volumetric and fixed tariff rates set by state regulators, is recognized as electricity is delivered and represents amounts both billed and unbilled. Customers are billed monthly and payment terms, set by the regulator, require payment within a month of billing.

Natural Gas Distribution (CenterPoint Energy and CERC). CERC distributes and transports natural gas to customers over time, and customers consume the natural gas when delivered. Revenue, consisting of both volumetric and fixed tariff rates set by the state governing agency for that service area, is recognized as natural gas is delivered and represents amounts both billed and unbilled. Discretionary services requested by the customer are satisfied at a point in time and revenue is recognized upon completion of service and the tariff rates set by the applicable state regulator. Payments of natural gas distribution, transportation and discretionary services are aggregated and received on a monthly basis.

Energy Services (CenterPoint Energy and CERC). The majority of CES natural gas sales contracts are considered a derivative, as the contracts typically have a stated minimum or contractual volume of delivery.

For contracts in which CES delivers the full requirement of the natural gas needed by the customer and a volume is not stated, a contract as defined under ASC 606 is created upon the customer’s exercise of its option to take natural gas. CES supplies natural gas to retail customers over time as customers consume the natural gas when delivered. For wholesale customers, CES supplies natural gas at a point in time because the wholesale customer is presumed to have storage capabilities. Control is transferred to both types of customers upon delivery of natural gas. Revenue is recognized on a monthly basis based on the estimated volume of natural gas delivered and the price agreed upon with the customer. Payments are received on a monthly basis.

AMAs are natural gas sales contracts under which CES also assumes management of a customer’s physical storage and/or transportation capacity. AMAs have two distinct performance obligations, which consist of natural gas sales and natural gas delivery because delivery could occur separate from the sale of natural gas (e.g., from storage to customer premises). Most AMAs’ natural gas sales performance obligations are accounted for as embedded derivatives. The transaction price is allocated between the sale of natural gas and the delivery based on the stand-alone selling price as stated in the contract. CES performs natural gas delivery over time as customers take delivery of the natural gas and recognizes revenue on an aggregated monthly basis based on the volume of natural gas delivered and the fees stated within the contract. Payments are received on a monthly basis.

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. The transaction is expected to close in the second quarter of 2020. For further information, see Notes 6 and 23.

Infrastructure Services (CenterPoint Energy). Infrastructure Services provides underground pipeline construction and repair services. The contracts are generally less than one year in duration and consist of fixed price, unit, and time and material customer contracts. Under unit or time and material contracts, Infrastructure Services performs construction and repair services under specific work-orders at prices established by master service agreements. The performance obligation is defined at the work-order level. These services are billed to customers monthly or more frequently for work completed based on units completed or the costs of time and material incurred and generally require payment within 30 days of billing. Infrastructure Services has the right to consideration from customers in an amount that corresponds directly with the performance obligation satisfied, and therefore recognizes revenue at a point in time in the amount to which it has the right to invoice, which results in accrued unbilled revenues at the end of each accounting period.

Under fixed price contracts, Infrastructure Services performs larger scale construction and repair services. Each contract is typically accounted for as a single performance obligation. Services performed under fixed price contracts are typically billed per the terms of the contract, which can range from completion of specific milestones to scheduled billing intervals. Billings occur monthly or more frequently for work completed and generally require payment within 30 days of billing. Revenue for fixed price contracts is recognized over time as control is transferred using the input method, considering costs incurred relative to total expected cost. Total expected cost is therefore a significant judgment affecting the amount and timing of revenue recognition. Infrastructure Services’ revenues are not subject to significant returns, refunds or warranty obligations.

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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 is expected to close in the second quarter of 2020. For further information, see Notes 6 and 23.

Contract Balances. When the timing of delivery of service is different from the timing of the payments made by customers and when the right to consideration is conditioned on something other than the passage of time, the Registrants recognize either a contract asset (performance precedes billing) or a contract liability (customer payment precedes performance). Those customers that prepay are represented by contract liabilities until the performance obligations are satisfied. The Registrants’ contract assets are included in Accrued unbilled revenues in their Consolidated Balance Sheets. On an aggregate basis as of December 31, 2019, the Registrants’ contract assets primarily relate to contracts in the Infrastructure Services segment where revenue is recognized using the input method. The Registrants’ contract liabilities are included in Accounts payable and Other current liabilities in their Consolidated Balance Sheets. On an aggregate basis as of December 31, 2019, the Registrants’ contract liabilities primarily relate to ESG contracts where revenue is recognized using the input method.

The opening and closing balances of accounts receivable, other accrued unbilled revenue, contract assets and contract liabilities from contracts with customers for the year ended December 31, 2019 are as follows:

CenterPoint Energy

	Accounts Receivable		Other Accrued Unbilled Revenues		Contract Assets		Contract Liabilities
	(in millions)
Opening balance as of December 31, 2018 (1)	$	516	$	373	$	—	$	3
Closing balance as of December 31, 2019	800		579		61		34
Increase	$	284	$	206	$	61	$	31

(1) Opening balances related to Vectren are as of February 1, 2019, and are thus excluded from the opening balance as of December 31, 2018.

The amount of revenue recognized in the year ended December 31, 2019 that was included in the opening contract liability was $47 million. The difference between the opening and closing balances of the contract liabilities primarily results from the timing difference between CenterPoint Energy’s performance and the customer’s payment, plus the addition of obligations acquired in the Merger.

Houston Electric

	Accounts Receivable			Other Accrued Unbilled Revenues		Contract Liabilities
	(in millions)
Opening balance as of December 31, 2018	$	234		$	110	$	3
Closing balance as of December 31, 2019	210			117		3
Increase (decrease)	$	(24	)	$	7	$	—

The amount of revenue recognized in the year ended December 31, 2019 that was included in the opening contract liability was $3 million. The difference between the opening and closing balances of the contract liabilities primarily results from the timing difference between Houston Electric’s performance and the customer’s payment.

CERC

	Accounts Receivable		Other Accrued Unbilled Revenues
	(in millions)
Opening balance as of December 31, 2018	$	282	$	263
Closing balance as of December 31, 2019	282		250
Increase (decrease)	$	—	$	(13	)

CERC does not have any opening or closing contract asset or contract liability balances.

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Remaining Performance Obligations (CenterPoint Energy). The table below discloses (1) the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) as of the end of the reporting period for contracts and (2) when CenterPoint Energy expects to recognize this revenue. Such contracts include fixed price contracts and energy performance and sustainable infrastructure services contracts of ESG, which are included in Corporate and Other.

	Rolling 12 Months		Thereafter		Total
	(in millions)
Revenue expected to be recognized on contracts in place as of December 31, 2019:
Infrastructure Services	$	254	$	—	$	254
Corporate and Other	84		752		836
	$	338	$	752	$	1,090

Practical Expedients and Exemption. Sales taxes and other similar taxes collected from customers are excluded from the transaction price. For contracts for which revenue from the satisfaction of the performance obligations is recognized in the amount invoiced, the practical expedient was elected and revenue expected to be recognized on these contracts has not been disclosed.

(6) Goodwill and Other Intangibles (CenterPoint Energy and CERC)

CenterPoint Energy’s goodwill by reportable segment as of December 31, 2018 and changes in the carrying amount of goodwill as of December 31, 2019 are as follows:

	December 31, 2018		Additions (1)		Impairment		December 31, 2019
	(in millions)
Indiana Electric Integrated	$	—	$	1,121	$	—	$	1,121
Natural Gas Distribution	746		2,566		—		3,312
Energy Services (2)	110		—		48		62
Infrastructure Services	—		220		—		220
Corporate and Other	11		438		—		449
Total	$	867	$	4,345	$	48	$	5,164

(1) This represents the allocation of goodwill to reportable segments from the Merger, changes from preliminary amounts previously reported and includes the final determination of fair value for each reportable segment. See Note 4.

(2) Amount presented is net of the accumulated goodwill impairment charge of $252 million recorded in 2012. As of December 31, 2019, CenterPoint Energy and CERC identified a triggering event to perform an interim goodwill impairment test and recognized a goodwill impairment on their Energy Services reporting unit which is included in Goodwill impairment on CenterPoint Energy’s and CERC’s Consolidated Statements of Income.

CERC’s goodwill by reportable segment as of December 31, 2019 and December 31, 2018 is as follows:

	December 31, 2018		Impairment		December 31, 2019
			(in millions)
Natural Gas Distribution	$	746	$	—	$	746
Energy Services (1)	110		48		62
Corporate and Other	11		—		11
Total	$	867	$	48	$	819

(1) Amount presented is net of the accumulated goodwill impairment charge of $252 million recorded in 2012.

CenterPoint Energy and CERC perform goodwill impairment tests at least annually and evaluate goodwill when events or changes in circumstances indicate that its carrying value may not be recoverable. The impairment evaluation for goodwill is performed by comparing the fair value of each reporting unit with the carrying amount of the reporting unit, including goodwill. The reporting units approximate the reportable segments, with the exception of ESG, which is a separate reporting unit but included

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in CenterPoint Energy’s Corporate and Other reportable segment. The estimated fair value of a reporting unit is primarily determined based on an income approach or a weighted combination of income and market approaches. If the carrying amount of the reporting unit is in excess of the estimated fair value of the reporting unit, then the excess amount is the impairment charge that should be recorded, not to exceed the carrying amount of goodwill. See Note 2(g) for further discussion.

CenterPoint Energy and CERC performed the annual goodwill impairment test on July 1 of each of 2019 and 2018 and determined that no goodwill impairment charge was required for any reporting unit in its annual test.

In connection with its preparation of financial statements for the year ended December 31, 2019, CenterPoint Energy and CERC, as applicable, identified triggering events for interim goodwill impairment tests at the Infrastructure Services and Energy Services reporting units. Early stage bids received from market participants during the exploration of strategic alternatives for these businesses at year-end indicated that the fair value of each reporting unit was more likely than not below the carrying value. 

On February 3, 2020, CenterPoint Energy, through its subsidiary VUSI, entered into the Securities Purchase Agreement to sell the businesses within its Infrastructure Services reporting unit. Per the Securities Purchase Agreement, VISCO will be converted from a wholly-owned corporation to a limited liability company that is disregarded for federal income tax purposes immediately prior to the closing of the transaction resulting in the sale of membership units at closing.  The sale will be considered an asset sale for tax purposes requiring the net deferred tax liabilities of approximately $123 million within the reporting unit as of December 31, 2019 to be recognized as a benefit to deferred income tax expense by CenterPoint Energy upon closing; therefore, any deferred tax assets and liabilities within the reporting unit are not included in the carrying amount of the assets and liabilities that will be transferred to the buyer. For further information, see Note 23.

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 reporting unit. Per the Equity Purchase Agreement, CES will be converted from a wholly-owned corporation to a limited liability company that is disregarded for federal income tax purposes immediately prior to the closing of the transaction resulting in the sale of membership units at closing. For further information, see Note 23.

The fair value of the Infrastructure Services reporting unit was estimated using a market approach deriving an estimated fair value as of December 31, 2019 based on the economic terms agreed upon within the Securities Purchase Agreement, a Level 2 fair value measurement.  As of December 31, 2019 the fair value of the Infrastructure Services reporting unit exceeded the carrying value (inclusive of deferred income tax liabilities of $123 million) and no impairment loss was recognized.

The fair value of the Energy Services reporting unit was estimated using a combination of the market approach and the income approach as of December 31, 2019, a Level 3 fair value measurement. CenterPoint Energy and CERC utilized the economic indicators of value received by market participants during the exploration of strategic alternatives to inform the fair value of substantially all of the businesses within this reporting unit as of December 31, 2019. Certain assets groups not constituting a business within the reporting unit were valued using an income approach.  CenterPoint Energy and CERC recognized an impairment loss on their Energy Services reporting unit of $48 million, the amount by which the carrying value (inclusive of deferred income tax liabilities of $25 million) exceeded the fair value as of December 31, 2019.

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The tables below present information on CenterPoint Energy’s other intangible assets recorded in Intangible assets, net on the Consolidated Balance Sheets and the related amortization expense included in Depreciation and amortization on CenterPoint Energy’s Statements of Consolidated Income, unless otherwise indicated.

	December 31, 2019							December 31, 2018
	Gross Carrying Amount		Accumulated Amortization			Net Balance		Gross Carrying Amount		Accumulated Amortization			Net Balance
	(in millions)
Customer relationships (1)	$	286	$	(43	)	$	243	$	86	$	(27	)	$	59
Covenants not to compete	4		(4		)	—		4		(3		)	1
Trade names (1)	58		(5		)	53		—		—			—
Construction backlog (1) (2)	27		(23		)	4		—		—			—
Operation and maintenance       agreements (1) (2)	12		(1		)	11		—		—			—
Other (1)	24		(14		)	10		16		(11		)	5
Total	$	411	$	(90	)	$	321	$	106	$	(41	)	$	65

(1) The fair value of intangible assets acquired through acquisitions has been finalized. See Note 4.

(2) Amortization expense related to the operation and maintenance agreements and construction backlog is included in Non-utility cost of revenues, including natural gas on CenterPoint Energy’s Statements of Consolidated Income.

	Year Ended December 31,
	2019		2018		2017
	(in millions)
Amortization expense of intangible assets recorded in    Depreciation and amortization (1) (2)	$	25	$	10	$	13
Amortization expense of intangible assets recorded in Non-utility cost of revenues, including natural gas (2)	24		—		—

(1) Includes $17 million for the year ended December 31, 2019 of amortization expense related to intangibles acquired in the Merger.

(2) The fair value of intangible assets, and related amortization assumptions, acquired through acquisitions during the year ended December 31, 2019, has been finalized. See Note 4.

The tables below present information on CERC’s other intangible assets recorded in Other non-current assets on CERC’s Consolidated Balance Sheets and the related amortization expense included in Depreciation and amortization on CERC’s Statements of Consolidated Income.

	December 31, 2019							December 31, 2018
	Gross Carrying Amount		Accumulated Amortization			Net Balance		Gross Carrying Amount		Accumulated Amortization			Net Balance
	(in millions)
Customer relationships	$	86	$	(32	)	$	54	$	86	$	(27	)	$	59
Covenants not to compete	4		(4		)	—		4		(3		)	1
Other	16		(14		)	2		16		(11		)	5
Total	$	106	$	(50	)	$	56	$	106	$	(41	)	$	65

	Year Ended December 31,
	2019		2018		2017
	(in millions)
Amortization expense of intangible assets recorded in    Depreciation and amortization	$	9	$	10	$	13

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CenterPoint Energy and CERC estimate that amortization expense of intangible assets with finite lives for the next five years will be as follows:

	Amortization Expense
	CenterPoint Energy		CERC
	(in millions)
2020	$	29	$	6
2021	25		6
2022	25		6
2023	24		5
2024	22		5

(7) Regulatory Matters

The following is a list of regulatory assets and liabilities reflected on the Registrants’ respective Consolidated Balance Sheets as of December 31, 2019 and 2018. The “amortization through” columns indicate the latest year when a regulatory asset or regulatory liability category will be fully amortized:

	December 31, 2019
	CenterPoint Energy				Houston Electric				CERC
	Amortization Through	(in millions)			Amortization Through	(in millions)			Amortization Through	(in millions)
Regulatory Assets:
Current regulatory assets (1)	2020	$	12		n/a	$	—		2020	$	12
Non-current regulatory assets:
Securitized regulatory assets	2024	788			2024	788			n/a	—
Unrecognized equity return (2)	2024	(168		)	2024	(168		)	n/a	—
Unamortized loss on reacquired debt (3)	2046	62			2046	62			n/a	—
Pension and postretirement-related regulatory asset (3)	Various (a)	637			TBD (b)	34			Various (a)	22
Hurricane Harvey restoration costs (3)	Various	68			TBD (b)	64			TBD (c)	4
Regulatory assets related to TCJA (3) (4)	Various	30			TBD (b)	23			2023	7
Asset retirement obligation (3)	Perpetual	131			Perpetual	26			Perpetual	94
Other regulatory assets-not earning a return (5)	Various (d)	147			Various	57			Various	48
Other regulatory assets	Various	422			Various	29			Various	16
Total non-current regulatory assets		2,117				915				191
Total regulatory assets		2,129				915				203
Regulatory Liabilities:
Current regulatory liabilities (6)	2020	47			n/a	—			2020	47
Non-current regulatory liabilities:
Regulatory liabilities related to TCJA (4)	Various	1,582			TBD (b)	821			Various	442
Estimated removal costs	Various	1,429			Various	244			Various	637
Other regulatory liabilities	Various	463			Various	223			Various	140
Total non-current regulatory liabilities		3,474				1,288				1,219
Total regulatory liabilities		3,521				1,288				1,266
Total regulatory assets and liabilities, net		$	(1,392	)		$	(373	)		$	(1,063	)

(a) Pension and postretirement-related regulatory assets balances are measured annually, and the ending amortization period may change based on the actuarial valuation.

(b) The recovery and amortization of these amounts are to be determined upon receipt of the final order.

(c) The recovery and amortization of a portion of these amounts are expected to be determined in the next rate case.

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(d) Other regulatory assets not-earning a return includes items with different amortization periods; therefore, the amortization is accounted for through various periods.

	December 31, 2018
	CenterPoint Energy			Houston Electric			CERC
	(in millions)
Regulatory Assets:
Current regulatory assets (1)	$	77		$	—		$	77
Non-current regulatory assets:
Securitized regulatory assets	1,059			1,059			—
Unrecognized equity return (2)	(213		)	(213		)	—
Unamortized loss on reacquired debt (3)	68			68			—
Pension and postretirement-related regulatory asset (3)	725			33			30
Hurricane Harvey restoration costs (3)	68			64			4
Regulatory assets related to TCJA (3) (4)	33			23			10
Asset retirement obligation (3)	109			24			85
Other regulatory assets-not earning a return (3)	81			55			26
Other regulatory assets	37			11			26
Total non-current regulatory assets	1,967			1,124			181
Total regulatory assets	2,044			1,124			258
Regulatory Liabilities:
Current regulatory liabilities (6)	38			17			21
Non-current regulatory liabilities:
Regulatory liabilities related to TCJA (4)	1,323			847			476
Estimated removal costs	886			269			617
Other regulatory liabilities	316			182			134
Total non-current regulatory liabilities	2,525			1,298			1,227
Total regulatory liabilities	2,563			1,315			1,248
Total regulatory assets and liabilities, net	$	(519	)	$	(191	)	$	(990	)

(1) Current regulatory assets are included in Prepaid expenses and other current assets in the Registrants’ respective Consolidated Balance Sheets.

(2) The unrecognized equity return will be recognized as it is recovered in rates through 2024. The timing of CenterPoint Energy’s and Houston Electric’s recognition of the equity return will vary each period based on amounts actually collected during the period. The actual amounts recognized are adjusted at least annually to correct any over-collections or under-collections during the preceding 12 months.

	Year Ended December 31,
	2019				2018				2017
	CenterPoint Energy		Houston Electric		CenterPoint Energy		Houston Electric		CenterPoint Energy		Houston Electric
Allowed equity return recognized	$	45	$	45	$	74	$	74	$	42	$	42

(3) Substantially all of these regulatory assets are not earning a return.

(4) The EDIT and deferred revenues will be recovered or refunded to customers as required by tax and regulatory authorities. See Note 15 for additional information.

(5) Regulatory assets acquired in the Merger and not earning a return were recorded at fair value as of the Merger Date. Such fair value adjustments are recognized over time until the regulatory asset is recovered.

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(6) Current regulatory liabilities are included in Other current liabilities in each of the Registrants’ respective Consolidated Balance Sheets.

Houston Electric Base Rate Case (CenterPoint Energy and Houston Electric)

On April 5, 2019, and subsequently adjusted in errata filings in May and June 2019, Houston Electric filed its base rate application with the PUCT and the cities in its service area seeking approval for revenue increases of approximately $194 million, exclusive of the EDIT refund discussed below.

The key proposals of the base rate case included:

• a rate base of $6.4 billion with a 50% debt/50% equity capital structure and a 10.4% ROE;

• a prudency determination on all capital investments made by Houston Electric since January 1, 2010;

• the establishment of a rider to refund unprotected EDIT resulting from the TCJA; and

• updated depreciation rates and approval to recover other costs.

On September 16, 2019, the ALJs issued a PFD. The PUCT began deliberating on the PFD (which is prepared by ALJs at a different state agency) during its November 14, 2019 open meeting, but delayed final determination for further consideration. The PUCT again discussed the Houston Electric rate case at its December 13, 2019 open meeting and concluded that the PUCT would consider settlement a reasonable approach to resolving the rate case and noted that Houston Electric had indicated settlement negotiations were already underway. Houston Electric updated the PUCT at its January 16, 2020 open meeting regarding the status of settlement discussions, indicating that the parties were working on a settlement and anticipated a final settlement in the near future. On January 23, 2020, Houston Electric filed a Stipulation and Settlement Agreement with the PUCT, which provides for the following, among other things:

• an overall revenue requirement increase of approximately $13 million;

• an ROE of 9.4%;

• a capital structure of 57.5% debt/42.5% equity;

• a refund of unprotected EDIT of $105 million plus carrying costs over approximately 30-36 months; and

• recovery of all retail transmission related costs through the TCRF.

Also, Houston Electric is not required to make a one-time refund of capital recovery from its TCOS and DCRF mechanisms. Future TCOS filings will take into account both ADFIT and EDIT until the final order from Houston Electric’s next base rate proceeding. No rate base items are expected to be written off; however, approximately $12 million in rate case expenses were written off in 2019. A base rate case application must be filed for Houston Electric no later than four years from the date of the PUCT’s final order in the proceeding. Additionally, Houston Electric will not file a DCRF in 2020, nor will a subsequent separate proceeding with the PUCT be instituted regarding EDIT on Houston Electric’s securitized assets.

Furthermore, under the terms of the Stipulation and Settlement Agreement, Houston Electric agreed to adopt certain ring-fencing measures to increase its financial separateness from CenterPoint Energy, which include the following:

• Houston Electric’s credit agreements and indentures shall not contain cross-default provisions by which a default by CenterPoint Energy or its other affiliates would cause a default at Houston Electric;

• The financial covenant in Houston Electric’s credit agreement shall not be related to any entity other than Houston Electric. Houston Electric shall not include in its debt or credit agreements any financial covenants or rating agency triggers related to any entity other than Houston Electric;

• Houston Electric shall not pledge its assets in respect of or guarantee any debt or obligation of any of its affiliates. Houston Electric shall not pledge, mortgage, hypothecate, or grant a lien upon the property of Houston Electric except pursuant to an exception in effect in Houston Electric’s current credit agreement, such as Houston Electric’s first mortgage and general mortgage;

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• Houston Electric shall maintain its own stand-alone credit facility, and Houston Electric shall not share its credit facility with any regulated or unregulated affiliate;

• Houston Electric shall maintain ratings with all three major credit ratings agencies;

• Houston Electric shall maintain a stand-alone credit rating;

• Houston Electric’s first mortgage bonds and general mortgage bonds shall be secured only with assets of Houston Electric;

• No Houston Electric assets may be used to secure the debt of CenterPoint Energy or its other affiliates;

• Houston Electric shall not hold out its credit as being available to pay the debt of any affiliates (provided that, for the avoidance of doubt, Houston Electric is not considered to be holding its credit out to pay the debt of affiliates, or in breach of any other ring-fencing measure, with respect to the $68 million of Houston Electric general mortgage bonds that currently serve as collateral for certain outstanding CenterPoint Energy pollution control bonds);

• Without prior approval of the PUCT, neither CenterPoint Energy nor any affiliate of CenterPoint Energy (excluding Houston Electric) may incur, guarantee, or pledge assets in respect of any incremental new debt that is dependent on: (1) the revenues of Houston Electric in more than a proportionate degree than the other revenues of CenterPoint Energy; or (2) the equity of Houston Electric;

• Houston Electric shall not transfer any material assets or facilities to any affiliates, other than a transfer that is on an arm’s length basis consistent with the PUCT’s affiliate standards applicable to Houston Electric;

• Except for its participation in an affiliate money pool, Houston Electric shall not commingle its assets with those of other CenterPoint Energy affiliates;

• Except for its participation in an affiliate money pool, Houston Electric shall not lend money to or borrow money from CenterPoint Energy; and

• Houston Electric shall notify the PUCT if its issuer credit rating or corporate credit rating as rated by any of the three major rating agencies falls below investment grade.

The PUCT approved the settlement at its February 14, 2020 open meeting. A final order from the PUCT is currently expected during the first quarter of 2020; however, motions for rehearing, if granted, could result in the order being issued after the first quarter of 2020. The rates are expected to be implemented 45 days after the final order is issued.

CenterPoint Energy and Houston Electric record pre-tax expense for (i) probable disallowances of capital investments and (ii) customer refund obligations and costs deferred in regulatory assets when recovery of such amounts is no longer considered probable.

(8) Stock-Based Incentive Compensation Plans and Employee Benefit Plans

(a) Stock-Based Incentive Compensation Plans (CenterPoint Energy)

CenterPoint Energy has LTIPs that provide for the issuance of stock-based incentives, including stock options, performance awards, restricted stock unit awards and restricted and unrestricted stock awards to officers, employees and non-employee directors.  Approximately 14 million shares of Common Stock are authorized under these plans for awards. CenterPoint Energy issues new shares of its Common Stock to satisfy stock-based payments related to LTIPs. Equity awards are granted to employees without cost to the participants.

Compensation costs for the performance and stock unit awards granted under LTIPs are measured using fair value and expected achievement levels on the grant date. For performance awards with operational goals, the achievement levels are revised as goals are evaluated. The fair value of awards granted to employees is based on the closing stock price of CenterPoint Energy’s Common Stock on the grant date. The compensation expense is recorded on a straight-line basis over the vesting period.  Forfeitures are estimated on the date of grant based on historical averages and estimates are updated periodically throughout the vesting period. 

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The performance awards granted in 2019, 2018 and 2017 are distributed based upon the achievement of certain objectives over a three-year performance cycle. The stock unit awards granted in 2019, 2018 and 2017 are service based. The stock unit awards generally vest at the end of a three-year period, provided, however, that stock unit awards granted to non-employee directors vested at the end of a one-year period (for awards granted in 2017) or vested immediately upon grant (for awards granted in 2019 and 2018). Upon vesting, both the performance and stock unit awards are issued to the participants along with the value of dividend equivalents earned over the performance cycle or vesting period.

The following table summarizes CenterPoint Energy’s expenses related to LTIPs for 2019, 2018 and 2017:

	Year Ended December 31,
	2019		2018		2017
	(in millions)
LTIP Compensation expense (1)	$	28	$	26	$	21
Income tax benefit recognized	7		6		8
Actual tax benefit realized for tax deductions	12		5		6

(1) Amounts presented in the table above are included in Operation and maintenance expense in CenterPoint Energy’s Statements of Consolidated Income and shown prior to any amounts capitalized.

The following tables summarize CenterPoint Energy’s LTIP activity for 2019:

	Year Ended December 31, 2019
	Shares (Thousands)		Weighted-Average Grant Date Fair Value		Remaining Average Contractual Life (Years)	Aggregate Intrinsic Value (2) (Millions)
Performance Awards (1)
Outstanding and non-vested as of December 31, 2018	3,818		$	23.91
Granted	1,413		31.16
Forfeited or canceled	(825	)	24.78
Vested and released to participants	(1,074	)	18.97
Outstanding and non-vested as of December 31, 2019	3,332		$	28.36	1.1	$	53
Stock Unit Awards
Outstanding and non-vested as of December 31, 2018	1,060		$	24.08
Granted	470		31.07
Forfeited or canceled	(131	)	27.95
Vested and released to participants	(433	)	20.72
Outstanding and non-vested as of December 31, 2019	966		$	28.46	1.2	$	26

 

(1) Reflects maximum performance achievement.

(2) Reflects the impact of current expectations of achievement and stock price.

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The weighted average grant date fair values per unit of awards granted were as follows for 2019, 2018 and 2017:

	Year Ended December 31,
	2019		2018		2017
	(In millions, except for per unit amounts)
Performance Awards
Weighted-average grant date fair value per unit of awards granted	$	31.16	$	26.74	$	26.64
Total intrinsic value of awards received by participants	36		12		7
Vested grant date fair value	20		9		5
Stock Unit Awards
Weighted-average grant date fair value per unit of awards granted	$	31.07	$	26.62	$	26.77
Total intrinsic value of awards received by participants	15		9		9
Vested grant date fair value	9		7		7

As of December 31, 2019, there was $34 million of total unrecognized compensation cost related to non-vested performance and stock awards which is expected to be recognized over a weighted-average period of 1.7 years.

(b) Pension Benefits (CenterPoint Energy)

CenterPoint Energy maintains a non-contributory qualified defined benefit pension plan covering eligible employees, with benefits determined using a cash balance formula. In addition to the non-contributory qualified defined benefit pension plan, CenterPoint Energy maintains unfunded non-qualified benefit restoration plans which allow participants to receive the benefits to which they would have been entitled under CenterPoint Energy’s non-contributory qualified pension plan except for federally mandated limits on qualified plan benefits or on the level of compensation on which qualified plan benefits may be calculated.

As a result of the Merger, CenterPoint Energy now also maintains three additional qualified defined benefit pension plans which are closed to new participants and a non-qualified supplemental retirement plan. The defined benefit pension plans cover eligible full-time regular employees and retirees of Vectren and are primarily non-contributory.

CenterPoint Energy’s net periodic cost includes the following components relating to pension, including the non-qualified benefit plans:

	Year Ended December 31,
	2019			2018			2017
	(in millions)
Service cost (1)	$	40		$	37		$	36
Interest cost (2)	96			79			89
Expected return on plan assets (2)	(105		)	(107		)	(97		)
Amortization of prior service cost (2)	9			9			9
Amortization of net loss (2)	52			43			58
Settlement cost (2) (3)	2			—			—
Curtailment gain (2) (4)	(1		)	—			—
Net periodic cost	$	93		$	61		$	95

 

(1) Amounts presented in the table above are included in Operation and maintenance expense in CenterPoint Energy’s Statements of Consolidated Income, net of regulatory deferrals and amounts capitalized.

(2) Amounts presented in the table above are included in Other, net in CenterPoint Energy’s Statements of Consolidated Income, net of regulatory deferrals.

(3) A one-time, non-cash settlement cost is required when the total lump sum distributions or other settlements of plan benefit obligations during a plan year exceed the service cost and interest cost components of the net periodic cost for that year. In 2019, CenterPoint Energy recognized a non-cash settlement cost due to lump sum settlement payments.

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(4) A curtailment gain or loss is required when the expected future services of a significant number of employees are reduced or eliminated for the accrual of benefits. In 2019, CenterPoint Energy recognized a pension curtailment gain related to employees who were terminated after the Merger closed.

CenterPoint Energy used the following assumptions to determine net periodic cost relating to pension benefits:

	Year Ended December 31,
	2019		2018		2017
Discount rate	4.35	%	3.65	%	4.15	%
Expected return on plan assets	6.00		6.00		6.00
Rate of increase in compensation levels	4.60		4.45		4.50

In determining net periodic benefit cost, CenterPoint Energy uses fair value, as of the beginning of the year, as its basis for determining expected return on plan assets.

The following table summarizes changes in the benefit obligation, plan assets, the amounts recognized in the Consolidated Balance Sheets as well as the key assumptions of CenterPoint Energy’s pension plans. The measurement dates for plan assets and obligations were December 31, 2019 and 2018.

	December 31,
	2019			2018
	(in millions, except for actuarial assumptions)
Change in Benefit Obligation
Benefit obligation, beginning of year	$	2,013		$	2,225
Plan obligations assumed in Merger	332			—
Service cost	40			37
Interest cost	96			79
Benefits paid	(244		)	(201		)
Actuarial (gain) loss (1)	216			(127		)
Plan amendment	1			—
Curtailment	(1		)	—
Benefit obligation, end of year	2,453			2,013
Change in Plan Assets
Fair value of plan assets, beginning of year	1,516			1,801
Plan assets assumed in Merger	286			—
Employer contributions	109			69
Benefits paid	(244		)	(201		)
Actual investment return	338			(153		)
Fair value of plan assets, end of year	2,005			1,516
Funded status, end of year	$	(448	)	$	(497	)
Amounts Recognized in Balance Sheets
Current liabilities-other	$	(8	)	$	(7	)
Other liabilities-benefit obligations	(440		)	(490		)
Net liability, end of year	$	(448	)	$	(497	)
Actuarial Assumptions
Discount rate (2)	3.20		%	4.35		%
Expected return on plan assets (3)	5.75			6.00
Rate of increase in compensation levels	4.95			4.60
Interest crediting rate	3.25			3.75

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(1) Significant sources of loss for 2019 include the decrease in discount rate from 4.35% to 3.20%. Significant sources of gain for 2018 include the increase in discount rate from 3.65% to 4.35% and the mortality projection scale change from MP2017 to MP2018.

(2) The discount rate assumption was determined by matching the projected cash flows of CenterPoint Energy’s plans against a hypothetical yield curve of high-quality corporate bonds represented by a series of annualized individual discount rates from one-half to 99 years.

(3) The expected rate of return assumption was developed using the targeted asset allocation of CenterPoint Energy’s plans and the expected return for each asset class.

The following table displays pension benefits related to CenterPoint Energy’s pension plans that have accumulated benefit obligations in excess of plan assets:

	December 31,
	2019				2018
	Pension (Qualified)		Pension (Non-qualified)		Pension (Qualified)		Pension (Non-qualified)
	(in millions)
Accumulated benefit obligation	$	2,352	$	68	$	1,930	$	61
Projected benefit obligation	2,385		68		1,952		61
Fair value of plan assets	2,005		—		1,516		—

The accumulated benefit obligation for all defined benefit pension plans on CenterPoint Energy’s Consolidated Balance Sheets was $2,420 million and $1,991 million as of December 31, 2019 and 2018, respectively.

Multi-employer Pension Plan

CenterPoint Energy, through its Infrastructure Services reportable segment, participates in several industry wide multi-employer pension plans for its collective bargaining employees which provide for monthly benefits based on length of service. The risks of participating in multi-employer pension plans are different from the risks of participating in single-employer pension plans in the following respects: (1) assets contributed to the multi-employer plan by one employer may be used to provide benefits to employees of other participating employers, (2) if a participating employer stops contributing to the plan, the unfunded obligations of the plan allocable to such withdrawing employer may be borne by the remaining participating employers and (3) if CenterPoint Energy stops participation in some of its multi-employer pension plans, CenterPoint Energy may be required to pay those plans an amount based on its allocable share of the underfunded status of the plan, referred to as a withdrawal liability.

Expense is recognized as payments are accrued for work performed or when withdrawal liabilities are probable and estimable. Expense associated with multi-employer plans of $52 million during the year ended December 31, 2019. During 2019, CenterPoint Energy made contributions to these multi-employer plans on behalf of employees that participate in approximately 215 local unions. Contracts with these unions are negotiated with trade agreements through two primary contractor associations. These trade agreements have varying expiration dates ranging from 2020 through 2022. The average contribution related to these local unions was less than $1 million, and the largest contribution was approximately $5 million. Multiple unions can contribute to a single multi-employer plan. CenterPoint Energy made contributions to at least 72 plans in 2019, eight of which are considered significant plans based on, among other things, the amount of the contributions, the number of employees participating in the plan, and the funded status of the plan.

CenterPoint Energy’s participation in the significant plans is outlined in the following table. The EIN / Pension Plan Number column provides the EIN and three-digit pension plan numbers. The most recent Pension Protection Act Zone Status available in 2019 is for the plan year end at January 31, 2019 for the Central Pension Fund, May 31, 2019 for the Indiana Pension Laborers Fund, December 31, 2018 for the Pipeline Industry Benefit Fund, December 31, 2018 for the Laborers District Council & Contractors’ Pension Fund of Ohio, April 30, 2019 for the Ohio Operating Engineers Pension Fund, April 30, 2019 for the Operating Engineers Local 324 Fringe Benefit Fund, December 31, 2018 for the Minnesota Laborers Pension Fund, and December 31, 2018 for the Laborers’ Combined Fund of Western Pennsylvania. Generally, plans in the red zone are less than 65% funded, plans in the yellow zone are less than 80% funded and plans in the green zone are at least 80% funded. The FIP/RP Status Pending / Implemented column indicates plans for which a FIP or RP is either pending or has been implemented. The multi-employer contributions listed in the table below are CenterPoint Energy’s multi-employer contributions made in 2019.

Federal law requires pension plans in endangered status to adopt a FIP and plans in critical status to adopt a RP aimed at

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restoring the financial health of the plan. In December 2014, the Multi-employer Pension Reform Act of 2014 was passed and permanently extended the Pension Protection Act of 2006 multi-employer plan critical and endangered status funding rules, among other things, including providing a provision for a plan sponsor to suspend or reduce benefit payments to preserve plans in critical and declining status.

		Pension Protection Act Zone Status		Multi-employer Contributions
Pension Fund	EIN/Pension Plan Number	2019	FIP/RP Status Pending/Implemented	2019		Surcharge Imposed
				(in millions)
Central Pension Fund	36-6052390-001	Green	No	$	12	No
Indiana Laborers Pension Fund	35-6027150-001	Green	No	5		No
Pipeline Industry Benefit Fund	73-0742835-001	Green	No	5		No
Laborers District Fund of Ohio	31-6129964-001	Green	No	4		No
Ohio Operating Engineers Pension Fund	31-6129968-001	Green	No	3		No
Operating Engineers Local #324 Fund (1)	38-1900637-001	Red	Implemented	3		No
Minnesota Laborers Pension Fund	41-6159599-001	Green	No	3		No
Laborers’ Combined Fund of Western PA (2)	25-6135576-001	Red	Implemented	2		No
Other				15
Total Contributions				$	52

(1) The Operating Engineers Local #324 Fringe Benefits Fund was certified to be in “critical” status for the plan year ending April 30, 2019. In an effort to improve the plan’s funding situation, on March 17, 2011, the trustees adopted a plan amendment, which reduced benefit accruals and eliminated some ancillary benefits, and adopted an RP that will be effective from May 1, 2013 through April 30, 2023 or until the plan is no longer in critical status. On April 27, 2015, the trustees updated the RP to change the annual standard for meeting the requirements of the RP. The trustees further updated the RP on January 29, 2019. The annual standard is that actuarial projections updated for each year show the fund is expected to remain solvent for a 20-year projection period.

(2) The Laborers’ Combined Fund of Western Pennsylvania was previously deemed in critical status. The trustees adopted a FIP that is scheduled to run through December 31, 2020 and provided for changes in adjustable benefits and increases in the employer contribution rate.

While not considered significant to CenterPoint Energy, there are four plans in red zone status receiving CenterPoint Energy contributions. There are also five other plans where CenterPoint Energy contributions exceed 5% of each plan’s total contributions; however, none of these plans are considered significant to CenterPoint Energy.

On February 3, 2020, CenterPoint Energy, through its subsidiary VUSI, entered into the Purchase Agreement to sell the businesses within its Infrastructure Services reportable segment. The transaction is expected to close in the second quarter of 2020. For further information, see Notes 6 and 23. As a result, CenterPoint Energy will no longer participate in the multi-employer pension plans discussed above.

(c) Postretirement Benefits

CenterPoint Energy provides certain healthcare and life insurance benefits for eligible retired employees on both a contributory and non-contributory basis. The Registrants’ employees (other than employees of Vectren and its subsidiaries) who were hired before January 1, 2018 and who have met certain age and service requirements at retirement, as defined in the plans, are eligible to participate in these benefit plans. Employees hired on or after January 1, 2018 are not eligible for these benefits, except that such employees represented by IBEW Local Union 66 are eligible to participate in certain of the benefits, subject to the applicable age and service requirements. With respect to retiree medical and prescription drug benefits, employees represented by the IBEW Local Union 66 who retire on or after January 1, 2017, and their dependents, receive any such benefits exclusively through the NECA/IBEW Family Medical Care Plan pursuant to the terms of the renegotiated collective bargaining agreement entered into in May 2016. Houston Electric and CERC are required to fund a portion of their obligations in accordance with rate orders. All other obligations are funded on a pay-as-you-go basis.

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As a result of the Merger, CenterPoint Energy now maintains an additional postretirement benefit plan. The postretirement benefit plan provides health care and life insurance benefits, which are a combination of self-insured and fully insured programs, to eligible Vectren retirees on both a contributory and non-contributory basis.

Postretirement benefits are accrued over the active service period of employees. The net postretirement benefit cost includes the following components:

	Year Ended December 31,
	2019									2018									2017
	CenterPoint Energy			Houston Electric			CERC			CenterPoint Energy			Houston Electric			CERC			CenterPoint Energy			Houston Electric			CERC
	(in millions)
Service cost (1)	$	3		$	1		$	1		$	2		$	—		$	1		$	2		$	1		$	1
Interest cost (2)	15			7			5			13			8			4			16			9			5
Expected return on plan assets (2)	(5		)	(4		)	(1		)	(5		)	(4		)	(1		)	(5		)	(4		)	(1		)
Amortization of prior service cost (credit) (2)	(5		)	(6		)	1			(5		)	(5		)	1			(5		)	(6		)	1
Net postretirement benefit cost (credit)	$	8		$	(2	)	$	6		$	5		$	(1	)	$	5		$	8		$	—		$	6

(1) Amounts presented in the table above are included in Operation and maintenance expense in each of the Registrants’ respective Statements of Consolidated Income, net of regulatory deferrals and amounts capitalized.

(2) Amounts presented in the table above are included in Other, net in each of the Registrants’ respective Statements of Consolidated Income, net of regulatory deferrals.

The following assumptions were used to determine net periodic cost relating to postretirement benefits:

	Year Ended December 31,
	2019						2018						2017
	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC
Discount rate	3.20	%	3.20	%	3.20	%	3.60	%	3.60	%	3.60	%	4.15	%	4.15	%	4.15	%
Expected return on plan assets	4.60		4.70		4.15		4.55		4.75		3.85		4.50		4.75		3.60

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The following table summarizes changes in the benefit obligation, plan assets, the amounts recognized in consolidated balance sheets and the key assumptions of the postretirement plans. The measurement dates for plan assets and benefit obligations were December 31, 2019 and 2018.

	December 31,
	2019									2018
	CenterPoint Energy			Houston Electric			CERC			CenterPoint Energy			Houston Electric			CERC
	(in millions)
Change in Benefit Obligation
Benefit obligation, beginning of year	$	331		$	166		$	110		$	386		$	225		$	109
Plan obligations assumed in Merger	37			—			—			—			—			—
Service cost	3			1			1			2			—			1
Interest cost	15			7			5			13			8			4
Participant contributions	8			2			4			7			2			4
Benefits paid	(26		)	(13		)	(8		)	(25		)	(13		)	(9		)
Plan amendment	9			3			5			—			—			—
Actuarial (gain) loss (1)	(21		)	(4		)	(15		)	(52		)	(56		)	1
Benefit obligation, end of year	356			162			102			331			166			110
Change in Plan Assets
Fair value of plan assets, beginning of year	114			89			25			120			93			26
Employer contributions	17			10			3			14			9			4
Participant contributions	8			2			4			7			2			4
Benefits paid	(26		)	(13		)	(8		)	(25		)	(13		)	(9		)
Actual investment return	15			13			3			(2		)	(2		)	—
Fair value of plan assets, end of year	128			101			27			114			89			25
Funded status, end of year	$	(228	)	$	(61	)	$	(75	)	$	(217	)	$	(77	)	$	(85	)
Amounts Recognized in Balance Sheets
Current liabilities-other	$	(8	)	$	—		$	(3	)	$	(6	)	$	—		$	(3	)
Other liabilities-benefit obligations	(220		)	(61		)	(72		)	(211		)	(77		)	(82		)
Net liability, end of year	$	(228	)	$	(61	)	$	(75	)	$	(217	)	$	(77	)	$	(85	)
Actuarial Assumptions
Discount rate (2)	3.25		%	3.25		%	3.25		%	4.35		%	4.35		%	4.35		%
Expected return on plan assets (3)	3.95			4.05			3.35			4.60			4.70			4.15
Medical cost trend rate assumed for the next year - Pre-65	5.50			5.50			5.50			5.95			5.95			5.95
Medical/prescription drug cost trend rate assumed for the next year - Post-65	5.75			5.75			5.75			28.60			28.60			28.60
Prescription drug cost trend rate assumed for the next year - Pre-65	8.00			8.00			8.00			9.20			9.20			9.20
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)	4.50			4.50			4.50			4.50			4.50			4.50
Year that the cost trend rates reach the ultimate trend rate - Pre-65	2028			2028			2028			2026			2026			2026
Year that the cost trend rates reach the ultimate trend rate - Post-65	2029			2029			2029			2027			2027			2027

(1) Significant sources of gain for 2019 include favorable cost trend rates and benefit claims experience in addition to the change in mortality projection scale from MP2018 to MP2019. Significant sources of gain for 2018 include the increase in the discount rate from 3.60% to 4.35%, favorable benefit claims experience and cost trend rates in addition to the change in mortality projection scale from MP2017 to MP2018.

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(2) The discount rate assumption was determined by matching the projected cash flows of the plans against a hypothetical yield curve of high-quality corporate bonds represented by a series of annualized individual discount rates from one-half to 99 years.

(3) The expected rate of return assumption was developed using the targeted asset allocation of the plans and the expected return for each asset class.

(d) Accumulated Other Comprehensive Income (Loss) (CenterPoint Energy and CERC)

CenterPoint Energy recognizes the funded status of its pension and other postretirement plans on its Consolidated Balance Sheets. To the extent this obligation exceeds amounts previously recognized in the Statements of Consolidated Income, CenterPoint Energy records a regulatory asset for that portion related to its rate regulated utilities. To the extent that excess liability does not relate to a rate regulated utility, the offset is recorded as a reduction to equity in accumulated other comprehensive income.

Amounts recognized in accumulated other comprehensive loss (gain) consist of the following:

	December 31,
	2019								2018
	Pension Benefits		Postretirement Benefits						Pension Benefits		Postretirement Benefits
	CenterPoint Energy		CenterPoint Energy			CERC			CenterPoint Energy		CenterPoint Energy			CERC
	(in millions)
Unrecognized actuarial loss (gain)	$	105	$	(16	)	$	(12	)	$	109	$	(7	)	$	(3	)
Unrecognized prior service cost	—		7			7			1		5			5
Deferred tax benefit	—		—			—			—		—			(9		)
Net amount recognized in accumulated other comprehensive loss (gain)	$	105	$	(9	)	$	(5	)	$	110	$	(2	)	$	(7	)

The changes in plan assets and benefit obligations recognized in other comprehensive income during 2019 are as follows:

	Pension Benefits			Postretirement Benefits
	CenterPoint Energy			CenterPoint Energy			CERC
	(in millions)
Net loss (gain)	$	4		$	(8	)	$	(6	)
Amortization of net loss	(8		)	—			—
Amortization of prior service cost	(1		)	1			(1		)
Total recognized in comprehensive income	$	(5	)	$	(7	)	$	(7	)
Total expense recognized in net periodic costs and Other comprehensive income	$	87		$	1		$	(1	)

(e) Pension Plan Assets (CenterPoint Energy)

In managing the investments associated with the benefit plans, CenterPoint Energy’s objective is to achieve and maintain a fully funded plan. This objective is expected to be achieved through an investment strategy that manages liquidity requirements while maintaining a long-term horizon in making investment decisions and efficient and effective management of plan assets.

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As part of the investment strategy discussed above, CenterPoint Energy maintained the following weighted average allocation targets for its pension plans as of December 31, 2019:

	Minimum		Maximum
U.S. equity	19	%	29	%
International equity	8	%	18	%
Real estate	3	%	9	%
Fixed income	52	%	62	%
Cash	0	%	2	%

The following tables set forth by level, within the fair value hierarchy (see Note 10), CenterPoint Energy’s pension plan assets at fair value as of December 31, 2019 and 2018:

	Fair Value Measurements as of December 31,
	2019										2018
	(Level 1)			(Level 2)		(Level 3)		Total			(Level 1)			(Level 2)		(Level 3)		Total
	(in millions)
Cash	$	(7	)	$	—	$	—	$	(7	)	$	19		$	—	$	—	$	19
Corporate bonds:
Investment grade or above	—			699		—		699			—			368		—		368
Equity securities:
U.S. companies	69			—		—		69			60			—		—		60
Cash received as collateral from securities lending	61			—		—		61			77			—		—		77
U.S. treasuries	232			—		—		232			196			—		—		196
Mortgage backed securities	—			8		—		8			—			6		—		6
Asset backed securities	—			3		—		3			—			1		—		1
Municipal bonds	—			44		—		44			—			27		—		27
Mutual funds (2)	270			—		—		270			167			—		—		167
International government bonds	—			21		—		21			—			16		—		16
Obligation to return cash received as collateral from securities lending	(61		)	—		—		(61		)	(77		)	—		—		(77		)
Total investments at fair value	$	564		$	775	$	—	$	1,339		$	442		$	418	$	—	$	860
Investments measured by net asset value per share or its equivalent (1) (2)								666										656
Total Investments								$	2,005									$	1,516

(1) Represents investments in common collective trust funds.

(2) The amounts invested in mutual funds and common collective trust funds were allocated as follows:

	As of December 31,
	2019				2018
	Mutual Funds		Common Collective Trust Funds		Mutual Funds		Common Collective Trust Funds
International equities (1)	31	%	29	%	85	%	41	%
U.S. equities	49	%	51	%	15	%	5	%
Real estate	1	%	6	%	—	%	—	%
Fixed income	19	%	14	%	—	%	54	%

(1) The amounts invested in international equities for 2018 include allocations of 34% in mutual funds and 4% in common collective trust funds,which were previously reported as allocations in emerging market equities.

The pension plans utilized both exchange traded and over-the-counter financial instruments such as futures, interest rate options and swaps that were marked to market daily with the gains/losses settled in the cash accounts. The pension plans did not include any holdings of CenterPoint Energy Common Stock as of December 31, 2019 or 2018.

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(f) Postretirement Plan Assets

In managing the investments associated with the postretirement plans, the Registrants’ objective is to achieve and maintain a fully funded plan. This objective is expected to be achieved through an investment strategy that manages liquidity requirements while maintaining a long-term horizon in making investment decisions and efficient and effective management of plan assets.

As part of the investment strategy discussed above, the Registrants maintained the following weighted average allocation targets for the postretirement plans as of December 31, 2019:

	CenterPoint Energy				Houston Electric				CERC
	Minimum		Maximum		Minimum		Maximum		Minimum		Maximum
U.S. equity	13	%	23	%	13	%	23	%	15	%	25	%
International equity	3	%	13	%	3	%	13	%	2	%	12	%
Fixed income	69	%	79	%	69	%	79	%	68	%	78	%
Cash	0	%	2	%	0	%	2	%	0	%	2	%

The following table presents mutual funds by level, within the fair value hierarchy, the Registrants’ postretirement plan assets at fair value as of December 31, 2019 and 2018:

	Fair Value Measurements as of December 31,
	2019								2018
	Mutual Funds
	(Level 1)		(Level 2)		(Level 3)		Total		(Level 1)		(Level 2)		(Level 3)		Total
	(in millions)
CenterPoint Energy	$	128	$	—	$	—	$	128	$	114	$	—	$	—	$	114
Houston Electric	101		—		—		101		89		—		—		89
CERC	27		—		—		27		25		—		—		25

The amounts invested in mutual funds were allocated as follows:

	As of December 31,
	2019						2018
	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC
Fixed income	71	%	71	%	69	%	74	%	74	%	73	%
U.S. equities	21	%	21	%	24	%	19	%	19	%	21	%
International equities	8	%	8	%	7	%	7	%	7	%	6	%

(g) Benefit Plan Contributions

The Registrants made the following contributions in 2019 and expect to make the following minimum contributions in 2020 to the indicated benefit plans below:

	Contributions in 2019						Expected Minimum Contributions in 2020
	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC
	(in millions)
Qualified pension plans	$	86	$	—	$	—	$	76	$	—	$	—
Non-qualified pension plans	23		—		—		7		—		—
Postretirement benefit plans	17		10		3		17		9		3

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The following benefit payments are expected to be paid by the pension and postretirement benefit plans:

	Pension Benefits		Postretirement Benefits
	CenterPoint Energy		CenterPoint Energy		Houston Electric		CERC
	(in millions)
2020	$	180	$	18	$	8	$	5
2021	178		18		8		4
2022	180		19		9		5
2023	181		20		10		5
2024	177		21		10		6
2025-2029	824		112		54		30

(h) Savings Plan

CenterPoint Energy maintains the CenterPoint Energy Savings Plan, a tax-qualified employee savings plan that includes a cash or deferred arrangement under Section 401(k) of the Code, and an employee stock ownership plan under Section 4975(e)(7) of the Code. Under the plan, participating employees may make pre-tax or Roth contributions and, if eligible, after-tax contributions up to certain federally mandated limits. Participating Registrants provide matching contributions and, as of January 1, 2020, nonelective contributions, if eligible, up to certain limits. CenterPoint Energy, through the Merger, also acquired additional defined contribution retirement savings plans sponsored by Vectren and its subsidiaries that are qualified under sections 401(a) and 401(k) of the Code, one of which merged into the CenterPoint Energy Savings Plan as of January 1, 2020.

The CenterPoint Energy Savings Plan has significant holdings of Common Stock. As of December 31, 2019, 11,051,800 shares of Common Stock were held by the savings plan, which represented approximately 13% of its investments. Given the concentration of the investments in Common Stock, the savings plan and its participants have market risk related to this investment. The savings plan limits the percentage of future contributions that can be invested in Common Stock to 25% and prohibits transfers of account balances where the transfer would result in more than 25% of a participant’s total account balance invested in Common Stock.

CenterPoint Energy allocates the savings plan benefit expense to Houston Electric and CERC related to their respective employees. The following table summarizes the Registrants’ savings plan benefit expense for 2019, 2018 and 2017:

	Year Ended December 31,
	2019						2018						2017
	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC
	(in millions)
Savings plan benefit  expenses (1)	$	58	$	18	$	18	$	43	$	17	$	18	$	41	$	17	$	17

(1) Amounts presented in the table above are included in Operation and maintenance expense in the Registrants’ respective Statements of Consolidated Income and shown prior to any amounts capitalized.

(i) Other Benefits Plans

The Registrants participate in CenterPoint Energy’s plans that provide postemployment benefits for certain former or inactive employees, their beneficiaries and covered dependents, after employment but before retirement (primarily healthcare and life insurance benefits for participants in the long-term disability plan).

CenterPoint Energy maintains non-qualified deferred compensation plans, including plans acquired in the Merger, that provide benefits payable to eligible directors, officers and select employees or their designated beneficiaries at specified future dates or upon termination, retirement or death. Benefit payments are made from the general assets of the participating Registrants.

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Expenses related to other benefit plans were recorded as follows:

	Year Ended December 31,
	2019						2018						2017
	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC
	(in millions)
Postemployment benefits	$	2	$	1	$	1	$	3	$	4	$	1	$	6	$	1	$	4
Deferred compensation plans	4		1		—		3		1		—		3		1		—

Amounts related to other benefit plans were included in Benefit Obligations in the Registrants’ accompanying Consolidated Balance Sheets as follows:

	December 31, 2019						December 31, 2018
	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC
	(in millions)
Postemployment benefits	$	11	$	3	$	7	$	11	$	3	$	7
Deferred compensation plans	41		8		3		42		9		3
Split-dollar life insurance arrangements	32		1		—		36		1		—

(j) Change in Control Agreements and Other Employee Matters

CenterPoint Energy has a change in control plan, which was amended and restated on May 1, 2017. The plan generally provides, to the extent applicable, in the case of a change in control of CenterPoint Energy and covered termination of employment, for severance benefits of up to three times annual base salary plus bonus, and other benefits. Certain CenterPoint Energy officers, including the Executive Chairman, are participants under the plan.

Certain key employees of Vectren and its subsidiaries have change in control agreements or employment agreements that provide payments and other benefits upon a covered termination of employment.

As of December 31, 2019, the Registrants’ employees were covered by collective bargaining agreements as follows:

		Percentage of Employees Covered
	Agreement Expiration	CenterPoint Energy		Houston Electric		CERC
IBEW Local 66	May 2020	10	%	51	%	—
OPEIU Local 12 and Mankato	March and May 2021	2	%	—		3	%
Gas Workers Union Local 340	April 2020	3	%	—		12	%
IBEW Locals 949 & 1393 and USW Locals 12213 & 7441	December 2020	4	%	—		7	%
USW Locals 13-227 & 13-1 and IBEW Local 702	June and July 2022	5	%	—		12	%
Teamsters Local 135	September 2021	—		—		—
UWUA Local 175	October 2021	1	%	—		—
Trade Agreements of Infrastructure Services through the DCA and PLCA (1)	Various expiration dates in 2020–2022	27	%	—		—
Total		52	%	51	%	34	%

(1) Infrastructure Services negotiates various trade agreements through contractor associations. The two primary associations are the DCA and the PLCA.  These trade agreements are with a variety of construction unions including Laborer’s International Union of North America, International Union of Operating Engineers, United Association of Journeymen and Apprentices of the Plumbing and Pipe Fitting Industry, and Teamsters. The trade agreements have varying expiration dates in 2020, 2021 and 2022. In addition, these subsidiaries have various project agreements and small local agreements.  These agreements expire upon completion of a specific project or on various dates throughout the year.

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(9) Derivative Instruments

The Registrants are exposed to various market risks. These risks arise from transactions entered into in the normal course of business. The Registrants utilize derivative instruments such as physical forward contracts, swaps and options to mitigate the impact of changes in commodity prices, weather and interest rates on operating results and cash flows.

(a) Non-Trading Activities

Commodity Derivative Instruments (CenterPoint Energy and CERC). CenterPoint Energy, through its Indiana utilities, and CERC, through CES, enter into certain derivative instruments to mitigate the effects of commodity price movements. Certain financial instruments used to hedge portions of the natural gas inventory of the Energy Services reportable segment are designated as fair value hedges for accounting purposes. Outstanding derivative instruments designated as economic hedges at the Indiana Utilities hedge long-term variable rate natural gas purchases. The Indiana Utilities have authority to refund and recover mark-to-market gains and losses associated with hedging natural gas purchases, and thus the gains and losses on derivatives are deferred in a regulatory liability or asset. All other financial instruments do not qualify or are not designated as cash flow or fair value hedges.

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. The transaction is expected to close in the second quarter of 2020. For further information, see Notes 6 and 23.

Interest Rate Risk Derivative Instruments. From time to time, the Registrants may enter into interest rate derivatives that are designated as economic or cash flow hedges. The objective of these hedges is to offset risk associated with interest rates borne by the Registrants in connection with an anticipated future fixed rate debt offering or other exposure to variable rate debt. The Indiana Utilities have authority to refund and recover mark-to-market gains and losses associated with hedging financing activity, and thus the gains and losses on derivatives are deferred in a regulatory liability or asset. For the impacts of cash flow hedges to Accumulated other comprehensive income, see Note 13.

The table below summarizes the Registrants’ outstanding interest rate hedging activity:

	December 31, 2019				December 31, 2018
Hedging Classification	Notional Principal
	CenterPoint  Energy (1)		Houston  Electric		CenterPoint  Energy		Houston  Electric
	(in millions)
Economic hedge	$	84	$	—	$	—	$	—
Cash flow hedge	—		—		450		450

(1) Relates to interest rate derivative instruments at SIGECO.

Weather Hedges (CenterPoint Energy and CERC). CenterPoint Energy and CERC have weather normalization or other rate mechanisms that largely mitigate the impact of weather on NGD in Arkansas, Indiana, Louisiana, Mississippi, Minnesota, Ohio and Oklahoma, as applicable. CenterPoint Energy’s and CERC’s NGD in Texas and CenterPoint Energy’s electric operations in Texas and Indiana do not have such mechanisms, although fixed customer charges are historically higher in Texas for NGD compared to its other jurisdictions. As a result, fluctuations from normal weather may have a positive or negative effect on CenterPoint Energy’s and CERC’s NGD’s results in Texas and on CenterPoint Energy’s electric operations’ results in its Texas and Indiana service territories.

CenterPoint Energy and CERC, as applicable, enter into winter season weather hedges from time to time for certain NGD jurisdictions and electric operations’ service territory to mitigate the effect of fluctuations from normal weather on results of operations and cash flows. These weather hedges are based on heating degree days at 10-year normal weather. Houston Electric and Indiana Electric do not enter into weather hedges.

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The tables below summarizes CenterPoint Energy’s and CERC’s weather hedge gain (loss) activity:

CenterPoint Energy

				Year Ended December 31,
Texas Operations	Winter Season	Bilateral Cap		2019		2018			2017
		(in millions)
NGD	2019 – 2020	$	8	$	2	$	—		$	—
NGD	2018 – 2019	9		—		—			—
NGD	2017 – 2018	8		—		(2		)	—
Electric operations	2019 – 2020	7		3		—			—
Electric operations	2018 – 2019	8		3		—			—
Electric operations	2017 – 2018	9		—		(2		)	—
Electric operations	2016 – 2017	9		—		—			(1		)
Total CenterPoint Energy (1)				$	8	$	(4	)	$	(1	)

CERC

				Year Ended December 31,
Texas Operations	Winter Season	Bilateral Cap		2019		2018			2017
		(in millions)
NGD	2019 – 2020	$	8	$	2	$	—		$	—
NGD	2018 – 2019	9		—		—			—
NGD	2017 – 2018	8		—		(2		)	—
Total CERC (1)				$	2	$	(2	)	$	—

(1) Weather hedge gains (losses) are recorded in Revenues in the Statements of Consolidated Income.

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(b) Derivative Fair Values and Income Statement Impacts

The following tables present information about derivative instruments and hedging activities. The first three tables provide a balance sheet overview of Derivative Assets and Liabilities as of December 31, 2019 and 2018, while the last two tables provide a breakdown of the related income statement impacts for the years ending December 31, 2019, 2018 and 2017.

Fair Value of Derivative Instruments and Hedged Items

CenterPoint Energy

		December 31, 2019				December 31, 2018
	Balance Sheet Location	Derivative Assets Fair Value		Derivative Liabilities Fair Value		Derivative Assets Fair Value		Derivative Liabilities Fair Value
		(in millions)
Derivatives designated as cash flow hedges:
Interest rate derivatives	Current Liabilities: Non-trading derivative liabilities	$	—	$	—	$	—	$	24
Derivatives designated as fair value hedges:
Natural gas derivatives (1) (2) (3)	Current Liabilities: Non-trading derivative liabilities	12		—		1		7
Derivatives not designated as hedging instruments:
Natural gas derivatives (1) (2) (3)	Current Assets: Non-trading derivative assets	139		3		103		3
Natural gas derivatives (1) (2) (3)	Other Assets: Non-trading derivative assets	58		—		38		—
Natural gas derivatives (1) (2) (3)	Current Liabilities: Non-trading derivative liabilities	73		184		62		173
Natural gas derivatives (1) (2) (3)	Other Liabilities: Non-trading derivative liabilities	10		54		16		25
Interest rate derivatives	Other Liabilities	—		10		—		—
Indexed debt securities derivative	Current Liabilities	—		893		—		601
Total CenterPoint Energy		$	292	$	1,144	$	220	$	833

(1) The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling 2,226 Bcf or a net 374 Bcf long position and 1,674 Bcf or a net 140 Bcf long position as of December 31, 2019 and 2018, respectively. Certain natural gas contracts hedge basis risk only and lack a fixed price exposure.

(2) Natural gas contracts are presented on a net basis in CenterPoint Energy’s Consolidated Balance Sheets as they are subject to master netting arrangements. This netting applies to all undisputed amounts due or past due and causes derivative assets (liabilities) to be ultimately presented net in a liability (asset) account within CenterPoint Energy’s Consolidated Balance Sheets. The net of total non-trading natural gas derivative assets and liabilities is detailed in the Offsetting of Natural Gas Derivative Assets and Liabilities table below.

(3) Derivative Assets and Derivative Liabilities include no material amounts related to physical forward transactions with Enable.

Houston Electric

		December 31, 2019				December 31, 2018
	Balance Sheet Location	Derivative Assets Fair Value		Derivative Liabilities Fair Value		Derivative Assets Fair Value		Derivative Liabilities Fair Value
		(in millions)
Derivatives designated as cash flow hedges:
Interest rate derivatives	Current Liabilities: Non-trading derivative liabilities	$	—	$	—	$	—	$	24
Total Houston Electric		$	—	$	—	$	—	$	24

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CERC

		December 31, 2019				December 31, 2018
	Balance Sheet Location	Derivative Assets Fair Value		Derivative Liabilities Fair Value		Derivative Assets Fair Value		Derivative Liabilities Fair Value
		(in millions)
Derivatives designated as fair value hedges:
Natural gas derivatives (1) (2) (3)	Current Liabilities: Non-trading derivative liabilities	$	12	$	—	$	1	$	7
Derivatives not designated as hedging instruments:
Natural gas derivatives (1) (2) (3)	Current Assets: Non-trading derivative assets	139		3		103		3
Natural gas derivatives (1) (2) (3)	Other Assets: Non-trading derivative assets	58		—		38		—
Natural gas derivatives (1) (2) (3)	Current Liabilities: Non-trading derivative liabilities	73		177		62		173
Natural gas derivatives (1) (2) (3)	Other Liabilities: Non-trading derivative liabilities	10		39		16		25
Total CERC		$	292	$	219	$	220	$	208

(1) The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling 2,226 Bcf or a net 374 Bcf long position and 1,674 Bcf or a net 140 Bcf long position as of December 31, 2019 and 2018, respectively. Certain natural gas contracts hedge basis risk only and lack a fixed price exposure.

(2) Natural gas contracts are presented on a net basis in CERC’s Consolidated Balance Sheets as they are subject to master netting arrangements. This netting applies to all undisputed amounts due or past due and causes derivative assets (liabilities) to be ultimately presented net in a liability (asset) account within CERC’s Consolidated Balance Sheets. The net of total non-trading natural gas derivative assets and liabilities is detailed in the Offsetting of Natural Gas Derivative Assets and Liabilities table below.

(3) Derivative Assets and Derivative Liabilities include no material amounts related to physical forward transactions with Enable.

Cumulative Basis Adjustment for Fair Value Hedges (CenterPoint Energy and CERC)

CenterPoint Energy
		December 31, 2019					December 31, 2018
	Balance Sheet Location	Carrying Amount of Hedged Assets/(Liabilities)		Cumulative Amount of Fair Value Hedging Adjustment Included in the Carrying Amount of Hedged Item			Carrying Amount of Hedged Assets/(Liabilities)		Cumulative Amount of Fair Value Hedging Adjustment Included in the Carrying Amount of Hedged Item
		(in millions)
Hedged items in fair value hedge relationship:
Natural gas inventory	Current Assets: Natural gas inventory	$	47	$	(13	)	$	57	$	1
Total CenterPoint Energy		$	47	$	(13	)	$	57	$	1

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CERC
		December 31, 2019					December 31, 2018
	Balance Sheet Location	Carrying Amount of Hedged Assets/(Liabilities)		Cumulative Amount of Fair Value Hedging Adjustment Included in the Carrying Amount of Hedged Item			Carrying Amount of Hedged Assets/(Liabilities)		Cumulative Amount of Fair Value Hedging Adjustment Included in the Carrying Amount of Hedged Item
		(in millions)
Hedged items in fair value hedge relationship:
Natural gas inventory	Current Assets: Natural gas inventory	$	47	$	(13	)	$	57	$	1
Total CERC		$	47	$	(13	)	$	57	$	1

Offsetting of Natural Gas Derivative Assets and Liabilities (CenterPoint Energy and CERC)

CenterPoint Energy
	December 31, 2019									December 31, 2018
	Gross Amounts Recognized (1)			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amount Presented in the Consolidated Balance Sheets (2)			Gross Amounts Recognized (1)			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amount Presented in the Consolidated Balance Sheets (2)
	(in millions)
Current Assets: Non-trading derivative assets	$	224		$	(88	)	$	136		$	166		$	(66	)	$	100
Other Assets: Non-trading derivative assets	68			(10		)	58			54			(16		)	38
Current Liabilities: Non-trading derivative liabilities	(187		)	136			(51		)	(183		)	81			(102		)
Other Liabilities: Non-trading derivative liabilities	(54		)	25			(29		)	(25		)	20			(5		)
Total CenterPoint Energy	$	51		$	63		$	114		$	12		$	19		$	31

CERC
	December 31, 2019									December 31, 2018
	Gross Amounts Recognized (1)			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amount Presented in the Consolidated Balance Sheets (2)			Gross Amounts Recognized (1)			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amount Presented in the Consolidated Balance Sheets (2)
	(in millions)
Current Assets: Non-trading derivative assets	$	224		$	(88	)	$	136		$	166		$	(66	)	$	100
Other Assets: Non-trading derivative assets	68			(10		)	58			54			(16		)	38
Current Liabilities: Non-trading derivative liabilities	(180		)	136			(44		)	(183		)	81			(102		)
Other Liabilities: Non-trading derivative liabilities	(39		)	25			(14		)	(25		)	20			(5		)
Total CERC	$	73		$	63		$	136		$	12		$	19		$	31

(1) Gross amounts recognized include some derivative assets and liabilities that are not subject to master netting arrangements.

(2) The derivative assets and liabilities on the Registrant’s respective Consolidated Balance Sheets exclude accounts receivable or accounts payable that, should they exist, could be used as offsets to these balances in the event of a default.

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Income Statement Impact of Hedge Accounting Activity (CenterPoint Energy and CERC)

CenterPoint Energy	Year Ended December 31,
	2019			2018			2017
	Location and Amount of Gain (Loss) recognized in Income on Hedging Relationship (1)
	Non-utility cost of revenues, including natural gas
	(in millions)
Total amounts presented in the statements of income in which the effects of hedges are recorded	$	4,029		$	4,364		$	3,785
Gain (loss) on fair value hedging relationships:
Commodity contracts:
Hedged items - Natural gas inventory	(14		)	(13		)	14
Derivatives designated as hedging instruments	14			13			(14		)
Amounts excluded from effectiveness testing recognized in earnings immediately	(213		)	(149		)	(67		)

(1) Income statement impact associated with cash flow hedge activity is related to gains and losses reclassified from Accumulated other comprehensive income into income. Amounts are immaterial for the years ended December 31, 2019, 2018 and 2017, respectively.

CERC	Year Ended December 31,
	2019			2018			2017
	Location and Amount of Gain (Loss) recognized in Income on Hedging Relationship (1)
	Non-utility cost of revenues, including natural gas
	(in millions)
Total amounts presented in the statements of income in which the effects of hedges are recorded	$	3,503		$	4,364		$	3,785
Gain (loss) on fair value hedging relationships:
Commodity contracts:
Hedged items - Natural gas inventory	(14		)	(13		)	14
Derivatives designated as hedging instruments	14			13			(14		)
Amounts excluded from effectiveness testing recognized in earnings immediately	(213		)	(149		)	(67		)

(1) Income statement impact associated with cash flow hedge activity is related to gains and losses reclassified from Accumulated other comprehensive income into income. Amounts are immaterial for the years ended December 31, 2019, 2018 and 2017, respectively.

CenterPoint Energy

		Year Ended December 31,
	Income Statement Location	2019			2018			2017
		(in millions)
Effects of derivatives not designated as hedging instruments on the income statement:
Commodity contracts	Gains (Losses) in Non-utility revenues	$	214		$	107		$	211
Indexed debt securities derivative	Gain (loss) on indexed debt securities	(292		)	(232		)	49
Interest rate derivatives	Gains in Other Income (Expense)	—			2			—
Total CenterPoint Energy		$	(78	)	$	(123	)	$	260

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CERC

		Year Ended December 31,
	Income Statement Location	2019		2018		2017
		(in millions)
Effects of derivatives not designated as hedging instruments on the income statement:
Commodity contracts	Gains (Losses) in Non-utility revenues	$	214	$	107	$	211
Total CERC		$	214	$	107	$	211

(c) Credit Risk Contingent Features (CenterPoint Energy and CERC)

CenterPoint Energy and CERC enter into financial derivative contracts containing material adverse change provisions. These provisions could require CenterPoint Energy or CERC to post additional collateral if the S&P or Moody’s credit ratings of CenterPoint Energy, Inc. or its subsidiaries, including CERC Corp., are downgraded.  

	December 31, 2019				December 31, 2018
	CenterPoint Energy		CERC		CenterPoint Energy		CERC
	(in millions)
Aggregate fair value of derivatives containing material adverse change provisions in a net liability position	$	1	$	1	$	1	$	1
Fair value of collateral already posted	—		—		—		—
Additional collateral required to be posted if credit risk contingent features triggered	1		1		—		—

(d) Credit Quality of Counterparties (CenterPoint Energy and CERC)

In addition to the risk associated with price movements, credit risk is also inherent in CenterPoint Energy’s and CERC’s non-trading derivative activities. Credit risk relates to the risk of loss resulting from non-performance of contractual obligations by a counterparty. The following tables show the composition of counterparties to the non-trading derivative assets:

CenterPoint Energy

	December 31, 2019				December 31, 2018
	Investment Grade (1)		Total (3)		Investment Grade (1)		Total (3)
	(in millions)
Energy marketers	$	4	$	16	$	11	$	24
End users (2)	27		178		30		114
Total CenterPoint Energy	$	31	$	194	$	41	$	138

CERC

	December 31, 2019				December 31, 2018
	Investment Grade (1)		Total (3)		Investment Grade (1)		Total (3)
	(in millions)
Energy marketers	$	4	$	16	$	11	$	24
End users (2)	27		178		30		114
Total CERC	$	31	$	194	$	41	$	138

(1) “Investment grade” is primarily determined using publicly available credit ratings and considers credit support (including parent company guarantees) and collateral (including cash and standby letters of credit). For unrated counterparties, CERC determines a synthetic credit rating by performing financial statement analysis and consider contractual rights and restrictions and collateral.

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(2) End users are comprised primarily of customers who have contracted to fix the price of a portion of their physical gas requirements for future periods.

(3) The amounts reflected in the table above were not impacted by collateral netting.

(10) Fair Value Measurements

Assets and liabilities that are recorded at fair value in the Registrants’ Consolidated Balance Sheets are categorized based upon the level of judgment associated with the inputs used to measure their value. Hierarchical levels, as defined below and directly related to the amount of subjectivity associated with the inputs to fair valuations of these assets and liabilities, are as follows:

Level 1: Inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date. The types of assets carried at Level 1 fair value generally are exchange-traded derivatives and equity securities, as well as natural gas inventory that has been designated as the hedged item in a fair value hedge.

Level 2: Inputs, other than quoted prices included in Level 1, are observable for the asset or liability, either directly or indirectly. Level 2 inputs include quoted prices for similar instruments in active markets, and inputs other than quoted prices that are observable for the asset or liability. Fair value assets and liabilities that are generally included in this category are derivatives with fair values based on inputs from actively quoted markets. A market approach is utilized to value the Registrants’ Level 2 natural gas derivative assets or liabilities. CenterPoint Energy’s Level 2 indexed debt securities derivative is valued using an option model and a discounted cash flow model, which uses projected dividends on the ZENS-Related Securities and a discount rate as observable inputs.

Level 3: Inputs are unobservable for the asset or liability, and include situations where there is little, if any, market activity for the asset or liability. Unobservable inputs reflect the Registrants’ judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. The Registrants develop these inputs based on the best information available, including the Registrants’ own data. A market approach is utilized to value the Registrants’ Level 3 assets or liabilities. As of December 31, 2019, CenterPoint Energy’s and CERC’s Level 3 assets and liabilities are comprised of physical natural gas forward contracts and options. Level 3 physical natural gas forward contracts and options are valued using a discounted cash flow model which includes illiquid forward price curve locations (ranging from $1.44 to $5.20 per MMBtu for CenterPoint Energy and from $1.44 to $5.20 per MMBtu for CERC) as an unobservable input. CenterPoint Energy’s and CERC’s Level 3 physical natural gas forward contracts and options derivative assets and liabilities consist of both long and short positions (forwards and options). Forward price decreases (increases) as of December 31, 2019 would have resulted in lower (higher) values, respectively, for long forwards and options and higher (lower) values, respectively, for short forwards and options.

The Registrants determine the appropriate level for each financial asset and liability on a quarterly basis and recognize transfers between levels at the end of the reporting period.  

The following tables present information about the Registrants’ assets and liabilities (including derivatives that are presented net) measured at fair value on a recurring basis as of December 31, 2019 and December 31, 2018, and indicate the fair value hierarchy of the valuation techniques utilized by the Registrants to determine such fair value.

CenterPoint Energy

	December 31, 2019											December 31, 2018
	Level 1		Level 2		Level 3		Netting (1)			Total		Level 1		Level 2		Level 3		Netting (1)			Total
Assets	(in millions)
Corporate equities	$	825	$	—	$	—	$	—		$	825	$	542	$	—	$	—	$	—		$	542
Investments, including money market funds (2)	49		—		—		—			49		66		—		—		—			66
Natural gas derivatives (3)(4)	—		250		42		(98		)	194		—		173		47		(82		)	138
Hedged portion of natural gas inventory	—		—		—		—			—		1		—		—		—			1
Total assets	$	874	$	250	$	42	$	(98	)	$	1,068	$	609	$	173	$	47	$	(82	)	$	747

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	December 31, 2019											December 31, 2018
	Level 1		Level 2		Level 3		Netting (1)			Total		Level 1		Level 2		Level 3		Netting (1)			Total
Liabilities
Indexed debt securities derivative	$	—	$	893	$	—	$	—		$	893	$	—	$	601	$	—	$	—		$	601
Interest rate derivatives	—		10		—		—			10		24		—		—		—			24
Natural gas derivatives (3)(4)	—		217		24		(161		)	80		—		191		17		(101		)	107
Hedged portion of natural gas inventory	13		—		—		—			13		—		—		—		—			—
Total liabilities	$	13	$	1,120	$	24	$	(161	)	$	996	$	24	$	792	$	17	$	(101	)	$	732

Houston Electric

	December 31, 2019										December 31, 2018
	Level 1		Level 2		Level 3		Netting		Total		Level 1		Level 2		Level 3		Netting		Total
Assets	(in millions)
Investments, including money market funds (2)	$	32	$	—	$	—	$	—	$	32	$	48	$	—	$	—	$	—	$	48
Total assets	$	32	$	—	$	—	$	—	$	32	$	48	$	—	$	—	$	—	$	48
Liabilities
Interest rate derivatives	$	—	$	—	$	—	$	—	$	—	$	24	$	—	$	—	$	—	$	24
Total liabilities	$	—	$	—	$	—	$	—	$	—	$	24	$	—	$	—	$	—	$	24

CERC

	December 31, 2019											December 31, 2018
	Level 1		Level 2		Level 3		Netting (1)			Total		Level 1		Level 2		Level 3		Netting (1)			Total
Assets	(in millions)
Corporate equities	$	2	$	—	$	—	$	—		$	2	$	2	$	—	$	—	$	—		$	2
Investments, including money market funds (2)	11		—		—		—			11		11		—		—		—			11
Natural gas derivatives (3)(4)	—		250		42		(98		)	194		—		173		47		(82		)	138
Hedged portion of natural gas inventory	—		—		—		—			—		1		—		—		—			1
Total assets	$	13	$	250	$	42	$	(98	)	$	207	$	14	$	173	$	47	$	(82	)	$	152
Liabilities
Natural gas derivatives (3)(4)	$	—	$	195	$	24	$	(161	)	$	58	$	—	$	191	$	17	$	(101	)	$	107
Hedged portion of natural gas inventory	13		—		—		—			13		—		—		—		—			—
Total liabilities	$	13	$	195	$	24	$	(161	)	$	71	$	—	$	191	$	17	$	(101	)	$	107

(1) Amounts represent the impact of legally enforceable master netting arrangements that allow CenterPoint Energy and CERC to settle positive and negative positions and also include cash collateral posted with the same counterparties as follows:

	December 31, 2019				December 31, 2018
	CenterPoint Energy		CERC		CenterPoint Energy		CERC
	(in millions)
Cash collateral posted with the same counterparties	$	63	$	63	$	19	$	19

(2) Amounts are included in Prepaid and Other Current Assets and Other Assets in the Consolidated Balance Sheets.

(3) Natural gas derivatives include no material amounts related to physical forward transactions with Enable.

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(4) Level 1 natural gas derivatives include exchange-traded derivatives cleared by the CME, which deems that financial instruments cleared by the CME are settled daily in connection with posted cash payments. As a result of this exchange rule, CME-related derivatives are considered to have no fair value at the balance sheet date for financial reporting purposes, and are presented in Level 1 net of posted cash; however, the derivatives remain outstanding and subject to future commodity price fluctuations until they are settled in accordance with their contractual terms. Derivative transactions cleared on exchanges other than the CME (e.g., the Intercontinental Exchange or ICE) continue to be reported on a gross basis.

The following table presents additional information about assets or liabilities, including derivatives that are measured at fair value on a recurring basis for which CenterPoint Energy and CERC have utilized Level 3 inputs to determine fair value:

	Year Ended December 31,
	2019						2018						2017
	CenterPoint Energy			CERC			CenterPoint Energy			CERC			CenterPoint Energy			CERC
	(in millions)
Beginning balance	$	30		$	30		$	(622	)	$	46		$	(704	)	$	13
Total gains	17			17			30			30			96			47
Total settlements	(22		)	(22		)	(39		)	(39		)	(11		)	(11		)
Transfers into Level 3	(1		)	(1		)	5			5			14			14
Transfers out of Level 3 (1)	(6		)	(6		)	656			(12		)	(17		)	(17		)
Ending balance (2)	$	18		$	18		$	30		$	30		$	(622	)	$	46
The amount of total gains for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the reporting date:
	$	12		$	12		$	18		$	18		$	87		$	38

(1) During 2018, CenterPoint Energy transferred its indexed debt securities derivative from Level 3 to Level 2 to reflect changes in the significance of the unobservable inputs used in the valuation.

(2) CenterPoint Energy and CERC did not have significant Level 3 purchases or sales during any of the years ended December 31, 2019, 2018 or 2017.

Estimated Fair Value of Financial Instruments

The fair values of cash and cash equivalents, investments in debt and equity securities classified as “trading” and short-term borrowings are estimated to be approximately equivalent to carrying amounts and have been excluded from the table below. The carrying amounts of non-trading derivative assets and liabilities and CenterPoint Energy’s ZENS indexed debt securities derivative are stated at fair value and are excluded from the table below. The fair value of each debt instrument is determined by multiplying the principal amount of each debt instrument by a combination of historical trading prices and comparable issue data. These liabilities, which are not measured at fair value in the Registrants’ Consolidated Balance Sheets, but for which the fair value is disclosed, would be classified as Level 2 in the fair value hierarchy.

	December 31, 2019						December 31, 2018
	CenterPoint Energy (1)		Houston Electric (1)		CERC		CenterPoint Energy (1)		Houston Electric (1)		CERC
Long-term debt, including current maturities	(in millions)
Carrying amount	$	15,093	$	4,950	$	2,546	$	9,140	$	4,717	$	2,371
Fair value	16,067		5,457		2,803		9,308		4,770		2,488

(1) Includes Securitization Bond debt.

Items measured at Fair Value on a Non-recurring Basis

CenterPoint Energy and CERC recorded a goodwill impairment charge of $48 million related to its Energy Services reporting unit in 2019. See Note 6.

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(11) Unconsolidated Affiliates (CenterPoint Energy and CERC)

CenterPoint Energy has the ability to significantly influence the operating and financial policies of Enable, a publicly traded MLP, and, accordingly, accounts for its investment in Enable’s common units using the equity method of accounting. Enable is considered to be a VIE because the power to direct the activities that most significantly impact Enable’s economic performance does not reside with the holders of equity investment at risk. However, CenterPoint Energy is not considered the primary beneficiary of Enable since it does not have the power to direct the activities of Enable that are considered most significant to the economic performance of Enable. As of December 31, 2019, CenterPoint Energy’s maximum exposure to loss related to Enable is limited to its investment in unconsolidated affiliate, its investment in Enable Series A Preferred Units and outstanding current accounts receivable from Enable.

Investment in Unconsolidated Affiliates (CenterPoint Energy):

	December 31, 2019		December 31, 2018
	(in millions)
Enable	$	2,406	$	2,482
Other (1)	2		—
Total	$	2,408	$	2,482

(1) Represents the fair value of non-utility equity investments acquired in the Merger.

CenterPoint Energy evaluates its equity method investments for impairment when factors indicate that a decrease in value of its investment has occurred and the carrying amount of its investment may not be recoverable. An impairment loss is recognized in earnings when an impairment is deemed to be other than temporary. As of December 31, 2019, CenterPoint Energy’s investment in Enable is $10.29 per unit and Enable’s common unit price closed at $10.03 per unit (approximately $61 million below carrying value). Based on an analysis of its investment in Enable as of December 31, 2019, CenterPoint Energy believes that the decline in the value of its investment is temporary, and that the carrying value of its investment of $2.4 billion will be recovered.

Equity in Earnings of Unconsolidated Affiliates, net (CenterPoint Energy):

	Year Ended December 31,
	2019		2018		2017
	(in millions)
Enable (1)	$	229	$	307	$	265
Other	1		—		—
Total	$	230	$	307	$	265

(1) Equity earnings for the year ended December 31, 2019 includes CenterPoint Energy’s share of Enable’s $86 million goodwill impairment recorded in the fourth quarter of 2019.

Limited Partner Interest and Units Held in Enable (CenterPoint Energy):

	As of December 31,
	2019				2018
	Limited Partner Interest (1)		Common Units	Enable Series A Preferred Units (2)	Limited Partner Interest (1)		Common Units	Enable Series A Preferred Units (2)
CenterPoint Energy (3)	53.7	%	233,856,623	14,520,000	54.0	%	233,856,623	14,520,000
OGE	25.5	%	110,982,805	—	25.6	%	110,982,805	—
Public unitholders	20.8	%	90,361,937	—	20.4	%	88,392,983	—
Total Units Outstanding	100.0	%	435,201,365	14,520,000	100.0	%	433,232,411	14,520,000

(1) Excludes the Enable Series A Preferred Units owned by CenterPoint Energy.

(2) The carrying amount of the Enable Series A Preferred Units, reflected as Preferred units - unconsolidated affiliate on CenterPoint Energy’s Consolidated Balance Sheets, was $363 million as of both December 31, 2019 and 2018. No

169

impairment charges or adjustment to carrying value were made as no observable price changes were identified in the current or prior reporting periods.

(3) Prior to the Internal Spin completed in September 2018, CenterPoint Energy’s investment in Enable’s common units, excluding the Enable Series A Preferred Units held directly by CenterPoint Energy, was held indirectly through CERC.

Generally, sales to any person or entity (including a series of sales to the same person or entity) of more than 5% of the aggregate of the common units CenterPoint Energy owns in Enable or sales to any person or entity (including a series of sales to the same person or entity) by OGE of more than 5% of the aggregate of the common units it owns in Enable are subject to mutual rights of first offer and first refusal set forth in Enable’s Agreement of Limited Partnership.

Interests Held in Enable GP (CenterPoint Energy):

CenterPoint Energy and OGE held the following interests in Enable GP as of both December 31, 2019 and 2018:

	Management  Rights (1)		Incentive Distribution Rights (2)
CenterPoint Energy (3)	50	%	40	%
OGE	50	%	60	%

(1) As of December 31, 2019, Enable is controlled jointly by CenterPoint Energy and OGE. Sale of CenterPoint Energy’s or OGE’s ownership interests in Enable GP to a third party is subject to mutual rights of first offer and first refusal, and CenterPoint Energy is not permitted to dispose of less than all of its interest in Enable GP.

(2) Enable is expected to pay a minimum quarterly distribution of $0.2875 per common unit on its outstanding common units to the extent it has sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to Enable GP and its affiliates, within 60 days after the end of each quarter. If cash distributions to Enable’s unitholders exceed $0.330625 per common unit in any quarter, Enable GP will receive increasing percentages or incentive distributions rights, up to 50%, of the cash Enable distributes in excess of that amount. In certain circumstances Enable GP will have the right to reset the minimum quarterly distribution and the target distribution levels at which the incentive distributions receive increasing percentages to higher levels based on Enable’s cash distributions at the time of the exercise of this reset election. To date, no incentive distributions have been made.

(3) Held indirectly through CNP Midstream.

Distributions Received from Enable (CenterPoint Energy and CERC):

CenterPoint Energy

	Year Ended December 31,
	2019				2018				2017
	Per Unit		Cash Distribution		Per Unit		Cash Distribution		Per Unit		Cash Distribution
	(in millions, except per unit amounts)
Enable common units (1)	$	1.2970	$	303	$	1.2720	$	297	$	1.2720	$	297
Enable Series A Preferred Units	2.5000		36		2.5000		36		2.5000		36
Total CenterPoint Energy			$	339			$	333			$	333

CERC

	Year Ended December 31,
	2018				2017
	Per Unit		Cash Distribution		Per Unit		Cash Distribution
	(in millions, except per unit amounts)
Enable common units (1)	$	0.9540	$	223	$	1.2720	$	297
Total CERC			223				297

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(1) Prior to the Internal Spin completed in September 2018, distributions from Enable were received by CERC. After such date, distributions from Enable were received directly by CenterPoint Energy (through CNP Midstream).

Transactions with Enable (CenterPoint Energy and CERC):

	Year Ended December 31,
	2019		2018		2017
CenterPoint Energy	(in millions)
Natural gas expenses, including transportation and storage costs (1)	$	120	$	122	$	115
Reimbursement of support services (2)	—		4		4
CERC
Natural gas expenses, including transportation and storage costs (1)	120		122		115
Reimbursement of support services (2)	—		4		4

(1) Included in Non-utility costs of revenues, including natural gas on CenterPoint Energy’s and CERC’s respective Statements of Consolidated Income.

(2) Represents amounts billed for certain support services provided to Enable. Actual support services costs are recorded net of reimbursement.

	December 31,
	2019		2018
CenterPoint Energy	(in millions)
Accounts payable for natural gas purchases from Enable	$	11	$	11
Accounts receivable for amounts billed for services provided to Enable	2		2
CERC
Accounts payable for natural gas purchases from Enable	11		11
Accounts receivable for amounts billed for services provided to Enable	2		2

CERC’s continuing involvement with Enable subsequent to the Internal Spin is limited to its natural gas purchases from Enable.

Summarized consolidated income (loss) information for Enable is as follows:

	Year Ended December 31,
	2019			2018			2017
	(in millions)
Operating revenues	$	2,960		$	3,431		$	2,803
Cost of sales, excluding depreciation and amortization	1,279			1,819			1,381
Depreciation and amortization	433			398			366
Operating income	569			648			528
Goodwill impairment	86			—			—
Net income attributable to Enable common units	360			485			400
Reconciliation of Equity in Earnings (Losses), net:
CenterPoint Energy’s interest	$	193		$	262		$	216
Basis difference amortization (1)	47			47			49
Loss on dilution, net of proportional basis difference recognition	(11		)	(2		)	—
CenterPoint Energy’s equity in earnings, net	$	229		$	307		$	265

(1) Equity in earnings of unconsolidated affiliate includes CenterPoint Energy’s share of Enable earnings adjusted for the amortization of the basis difference of CenterPoint Energy’s original investment in Enable and its underlying equity in net assets of Enable. The basis difference is being amortized through the year 2048.

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Summarized consolidated balance sheet information for Enable is as follows:

	December 31,
	2019			2018
	(in millions)
Current assets	$	389		$	449
Non-current assets	11,877			11,995
Current liabilities	780			1,615
Non-current liabilities	4,077			3,211
Non-controlling interest	37			38
Preferred equity	362			362
Accumulated other comprehensive loss	(3		)	—
Enable partners’ equity	7,013			7,218
Reconciliation of Investment in Enable:
CenterPoint Energy’s ownership interest in Enable partners’ equity	$	3,767		$	3,896
CenterPoint Energy’s basis difference	(1,361		)	(1,414		)
CenterPoint Energy’s equity method investment in Enable	$	2,406		$	2,482

Discontinued Operations (CERC):

On September 4, 2018, CERC completed the Internal Spin. CERC executed the Internal Spin to, among other things, enhance the access of CERC and CenterPoint Energy to low cost debt and equity through increased transparency and understandability of the financial statements, improve CERC’s credit quality by eliminating the exposure to Enable’s midstream business and provide clarity of internal reporting and performance metrics to enhance management’s decision making for CERC and CNP Midstream.

The Internal Spin represents a significant strategic shift that has a material effect on CERC’s operations and financial results and, as a result, CERC’s distribution of its equity investment in Enable met the criteria for discontinued operations classification. CERC has no continuing involvement in the equity investment of Enable. Therefore, CERC’s equity in earnings and related income taxes have been classified as Income from discontinued operations, net of tax, in CERC’s Statements of Consolidated Income for the periods presented. CERC’s equity method investment and related deferred income tax liabilities have been classified as Investment in unconsolidated affiliate - discontinued operations and Deferred income taxes, net - discontinued operations, respectively, in CERC’s Consolidated Balance Sheets for the periods presented. The following table presents amounts included in Income from discontinued operations, net of tax in CERC’s Statements of Consolidated Income.

	Year Ended December 31,
	2018		2017
	(in millions)
Equity in earnings of unconsolidated affiliate, net	$	184	$	265
Income tax expense	46		104
Income from discontinued operations, net of tax	$	138	$	161

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(12) Indexed Debt Securities (ZENS) and Securities Related to ZENS (CenterPoint Energy)

(a) Investment in Securities Related to ZENS

A subsidiary of CenterPoint Energy holds shares of certain securities detailed in the table below, which are classified as trading securities and are expected to be held to facilitate CenterPoint Energy’s ability to meet its obligation under the ZENS. Unrealized gains and losses resulting from changes in the market value of the ZENS-Related Securities are recorded in CenterPoint Energy’s Statements of Consolidated Income.

	Shares Held at December 31,
	2019	2018
AT&T Common	10,212,945	10,212,945
Charter Common	872,503	872,912

(b) ZENS

In September 1999, CenterPoint Energy issued ZENS having an original principal amount of $1.0 billion of which $828 million remained outstanding as of December 31, 2019. Each ZENS is exchangeable at the holder’s option at any time for an amount of cash equal to 95% of the market value of the reference shares attributable to such note. The number and identity of the reference shares attributable to each ZENS are adjusted for certain corporate events.

CenterPoint Energy’s reference shares for each ZENS consisted of the following:

	December 31,
	2019	2018
	(in shares)
AT&T Common	0.7185	0.7185
Charter Common	0.061382	0.061382

CenterPoint Energy pays interest on the ZENS at an annual rate of 2% plus the amount of any quarterly cash dividends paid in respect of the reference shares attributable to the ZENS. The principal amount of the ZENS is subject to increases or decreases to the extent that the annual yield from interest and cash dividends on the reference shares is less than or more than 2.309%. The adjusted principal amount is defined in the ZENS instrument as “contingent principal.” As of December 31, 2019, the ZENS, having an original principal amount of $828 million and a contingent principal amount of $75 million, were outstanding and were exchangeable, at the option of the holders, for cash equal to 95% of the market value of the reference shares attributable to the ZENS. As of December 31, 2019, the market value of such shares was approximately $822 million, which would provide an exchange amount of $944 for each $1,000 original principal amount of ZENS. At maturity of the ZENS in 2029, CenterPoint Energy will be obligated to pay in cash the higher of the contingent principal amount of the ZENS or an amount based on the then-current market value of the reference shares, which will include any additional publicly-traded securities distributed with respect to the current reference shares prior to maturity.

The ZENS obligation is bifurcated into a debt component and a derivative component (the holder’s option to receive the appreciated value of the reference shares at maturity). The bifurcated debt component accretes through interest charges annually up to the contingent principal amount of the ZENS in 2029. Such accretion will be reduced by annual cash interest payments, as described above. The derivative component is recorded at fair value and changes in the fair value of the derivative component are recorded in CenterPoint Energy’s Statements of Consolidated Income. Changes in the fair value of the ZENS-Related Securities held by CenterPoint Energy are expected to substantially offset changes in the fair value of the derivative component of the ZENS.

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The following table sets forth summarized financial information regarding CenterPoint Energy’s investment in ZENS-Related Securities and each component of CenterPoint Energy’s ZENS obligation. 

	ZENS-Related Securities			Debt Component of ZENS			Derivative Component of ZENS
	(in millions)
Balance as of December 31, 2016	$	953		$	114		$	717
Accretion of debt component of ZENS	—			27			—
2% interest paid	—			(17		)	—
Distribution to ZENS holders	—			(2		)	—
Gain on indexed debt securities	—			—			(49		)
Gain on ZENS-Related Securities	7			—			—
Balance as of December 31, 2017	960			122			668
Accretion of debt component of ZENS	—			21			—
2% interest paid	—			(17		)	—
Sale of ZENS-Related Securities	(398		)	—			—
Distribution to ZENS holders	—			(102		)	(46		)
Gain on indexed debt securities	—			—			(21		)
Loss on ZENS-Related Securities	(22		)	—			—
Balance as of December 31, 2018	540			24			601
Accretion of debt component of ZENS	—			17			—
2% interest paid	—			(17		)	—
Distribution to ZENS holders	—			(5		)	—
Loss on indexed debt securities	—			—			292
Gain on ZENS-Related Securities	282			—			—
Balance as of December 31, 2019	$	822		$	19		$	893

(13) Equity (CenterPoint Energy)

Dividends Declared and Paid (CenterPoint Energy)

CenterPoint Energy declared dividends on its Common Stock during 2019, 2018 and 2017 as presented in the table below:

Declaration Date	Record Date	Payment Date	Per Share		Total (in millions)
October 17, 2019	November 21, 2019	December 12, 2019	$	0.2875	$	144
July 31, 2019	August 15, 2019	September 12, 2019	0.2875		145
April 25, 2019	May 16, 2019	June 13, 2019	0.2875		144
Total 2019			$	0.8625	$	433
December 12, 2018	February 21, 2019	March 14, 2019	$	0.2875	$	144
October 23, 2018	November 15, 2018	December 13, 2018	0.2775		139
July 26, 2018	August 16, 2018	September 13, 2018	0.2775		120
April 26, 2018	May 17, 2018	June 14, 2018	0.2775		120
Total 2018			$	1.1200	$	523

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Declaration Date	Record Date	Payment Date	Per Share		Total (in millions)
December 13, 2017	February 15, 2018	March 8, 2018	$	0.2775	$	120
October 25, 2017	November 16, 2017	December 8, 2017	0.2675		116
July 27, 2017	August 16, 2017	September 8, 2017	0.2675		115
April 27, 2017	May 16, 2017	June 9, 2017	0.2675		115
January 5, 2017	February 16, 2017	March 10, 2017	0.2675		115
Total 2017			$	1.3475	$	581

CenterPoint Energy declared dividends on its Series A Preferred Stock during 2019 and 2018 as presented in the table below:

Declaration Date	Record Date	Payment Date	Per Share		Total (in millions)
July 31, 2019	August 15, 2019	September 3, 2019	$	30.6250	$	24
Total 2019			$	30.6250	$	24
December 12, 2018	February 15, 2019	March 1, 2019	$	32.1563	$	26
Total 2018			$	32.1563	$	26

CenterPoint Energy declared dividends on its Series B Preferred Stock during 2019 and 2018 as presented in the table below:

Declaration Date	Record Date	Payment Date	Per Share		Total (in millions)
October 17, 2019	November 15, 2019	December 2, 2019	$	17.5000	$	17
July 31, 2019	August 15, 2019	September 3, 2019	17.5000		17
April 25, 2019	May 15, 2019	June 3, 2019	17.5000		17
Total 2019			$	52.5000	$	51
December 12, 2018	February 15, 2019	March 1, 2019	$	17.5000	$	17
October 23, 2018	November 15, 2018	December 1, 2018	11.6667		11
Total 2018			$	29.1667	$	28

There were no Series A Preferred Stock or Series B Preferred Stock outstanding or dividends declared in 2017.

Dividend Requirement on Preferred Stock

	Year Ended December 31,
	2019		2018		2017
	(in millions)
Series A Preferred Stock	$	49	$	18	$	—
Series B Preferred Stock	68		17		—
Total preferred stock dividend requirement	$	117	$	35	$	—

Series A Preferred Stock

On August 22, 2018, CenterPoint Energy completed the issuance of 800,000 shares of its Series A Preferred Stock, at a price of $1,000 per share, resulting in net proceeds of $790 million after issuance costs. The aggregate liquidation value of the Series A Preferred Stock is $800 million with a per share liquidation value of $1,000.

CenterPoint Energy used the net proceeds from the Series A Preferred Stock offering to fund a portion of the Merger and to pay related fees and expenses.

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Dividends. The Series A Preferred Stock accrue cumulative dividends, calculated as a percentage of the stated amount per share, at a fixed annual rate of 6.125% per annum to, but excluding, September 1, 2023, and at an annual rate of three-month LIBOR plus a spread of 3.270% thereafter to be paid in cash if, when and as declared. If declared, prior to September 1, 2023, dividends are payable semi-annually in arrears on each March 1 and September 1, beginning on March 1, 2019, and, for the period commencing on September 1, 2023, dividends are payable quarterly in arrears each March 1, June 1, September 1 and December 1, beginning on December 1, 2023. Cumulative dividends earned during the applicable periods are presented on CenterPoint Energy’s Statements of Consolidated Income as Preferred stock dividend requirement.

Optional Redemption. On or after September 1, 2023, CenterPoint Energy may, at its option, redeem the Series A Preferred Stock, in whole or in part, at any time or from time to time, for cash at a redemption price of $1,000 per share, plus any accumulated and unpaid dividends thereon to, but excluding, the redemption date.

At any time within 120 days after the conclusion of any review or appeal process instituted by CenterPoint Energy, if any, following the occurrence of a ratings event, CenterPoint Energy may, at its option, redeem the Series A Preferred Stock in whole, but not in part, at a redemption price in cash per share equal to $1,020 (102% of the liquidation value of $1,000) plus an amount equal to all accumulated and unpaid dividends thereon to, but excluding, the redemption date, whether or not declared.

Ranking. The Series A Preferred Stock, with respect to anticipated dividends and distributions upon CenterPoint Energy’s liquidation or dissolution, or winding-up of CenterPoint Energy’s affairs, ranks or will rank:

• senior to Common Stock and to each other class or series of capital stock established after the initial issue date of the Series A Preferred Stock that is expressly made subordinated to the Series A Preferred Stock;

• on a parity with any class or series of capital stock established after the initial issue date of the Series A Preferred Stock that is not expressly made senior or subordinated to the Series A Preferred Stock, including the Series B Preferred Stock;

• junior to any class or series of capital stock established after the initial issue date of the Series A Preferred Stock that is expressly made senior to the Series A Preferred Stock;

• junior to all existing and future indebtedness (including indebtedness outstanding under CenterPoint Energy’s credit facilities, senior notes and commercial paper) and other liabilities with respect to assets available to satisfy claims against CenterPoint Energy; and

• structurally subordinated to any existing and future indebtedness and other liabilities of CenterPoint Energy’s subsidiaries and capital stock of CenterPoint Energy’s subsidiaries held by third parties.

Voting Rights. Holders of the Series A Preferred Stock generally will not have voting rights. Whenever dividends on shares of Series A Preferred Stock have not been declared and paid for the equivalent of three or more semi-annual or six or more quarterly dividend periods (including, for the avoidance of doubt, the dividend period beginning on, and including, the original issue date and ending on, but excluding, March 1, 2019), whether or not consecutive, the holders of such shares of Series A Preferred Stock, voting together as a single class with holders of any and all other series of voting preferred stock (as defined in the Statement of Resolution for the Series A Preferred Stock) then outstanding, will be entitled at CenterPoint Energy’s next annual or special meeting of shareholders to vote for the election of a total of two additional members of CenterPoint Energy’s Board of Directors, subject to certain limitations. This right will terminate if and when all accumulated dividends have been paid in full and, upon such termination, the term of office of each director so elected will terminate at such time and the number of directors on CenterPoint Energy’s Board of Directors will automatically decrease by two, subject to the revesting of such rights in the event of each subsequent nonpayment.

Series B Preferred Stock

On October 1, 2018, CenterPoint Energy completed the issuance of 19,550,000 depositary shares, each representing a 1/20th interest in a share of its Series B Preferred Stock, at a price of $50 per depositary share, resulting in net proceeds of $950 million after issuance costs. The aggregate liquidation value of Series B Preferred Stock is $978 million with a per share liquidation value of $1,000. The amount issued included 2,550,000 depositary shares issued pursuant to the exercise in full of the option granted to the underwriters to purchase additional depositary shares.

CenterPoint Energy used the net proceeds from the offering of depositary shares, each representing a 1/20th interest in a share of its Series B Preferred Stock, to fund a portion of the Merger and to pay related fees and expenses.

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Dividends. Dividends on the Series B Preferred Stock will be payable on a cumulative basis when, as and if declared at an annual rate of 7.00% on the liquidation value of $1,000 per share. CenterPoint Energy may pay declared dividends in cash or, subject to certain limitations, in shares of Common Stock, or in any combination of cash and shares of Common Stock on March 1, June 1, September 1 and December 1 of each year, commencing on December 1, 2018 and ending on, and including, September 1, 2021. Cumulative dividends earned during the applicable periods are presented on CenterPoint Energy’s Statements of Consolidated Income as Preferred stock dividend requirement.

Mandatory Conversion. Unless earlier converted or redeemed, each share of the Series B Preferred Stock will automatically convert on the mandatory conversion date, which is expected to be September 1, 2021, into not less than 30.5820 and not more than 36.6980 shares of Common Stock, subject to certain anti-dilution adjustments. Correspondingly, the conversion rate per depositary share will be not less than 1.5291 and not more than 1.8349 shares of Common Stock, subject to certain anti-dilution adjustments. The conversion rate will be determined based on a preceding 20-day volume-weighted-average-price of Common Stock.

The following table illustrates the conversion rate per share of the Series B Preferred Stock, subject to certain anti-dilution adjustments:

Applicable Market Value of the Common Stock	Conversion Rate per Share of Series B Preferred Stock
Greater than $32.6990 (threshold appreciation price)	30.5820 shares of Common Stock
Equal to or less than $32.6990 but greater than or equal to $27.2494	Between 30.5820 and 36.6980 shares of Common Stock, determined by dividing $1,000 by the applicable market value
Less than $27.2494 (initial price)	36.6980 shares of Common Stock

The following table illustrates the conversion rate per depositary share, subject to certain anti-dilution adjustments:

Applicable Market Value of the Common Stock	Conversion Rate per Depository Share
Greater than $32.6990 (threshold appreciation price)	1.5291 shares of Common Stock
Equal to or less than $32.6990 but greater than or equal to $27.2494	Between 1.5291 and 1.8349 shares of Common Stock, determined by dividing $50 by the applicable market value
Less than $27.2494 (initial price)	1.8349 shares of Common Stock

Optional Conversion of the Holder. Other than during a fundamental change conversion period, and unless CenterPoint Energy has redeemed the Series B Preferred Stock, a holder of the Series B Preferred Stock may, at any time prior to September 1, 2021, elect to convert such holder’s shares of the Series B Preferred Stock, in whole or in part, at the minimum conversion rate of 30.5820 shares of Common Stock per share of the Series B Preferred Stock (equivalent to 1.5291 shares of Common Stock per depositary share), subject to certain anti-dilution and other adjustments. Because each depositary share represents a 1/20th fractional interest in a share of the Series B Preferred Stock, a holder of depositary shares may convert its depositary shares only in lots of 20 depositary shares.

Fundamental Change Conversion. If a fundamental change occurs on or prior to September 1, 2021, holders of the Series B Preferred Stock will have the right to convert their shares of the Series B Preferred Stock, in whole or in part, into shares of Common Stock at the fundamental change conversion rate during the period beginning on, and including, the effective date of such fundamental change and ending on, and including, the date that is 20 calendar days after such effective date (or, if later, the date that is 20 calendar days after holders receive notice of such fundamental change, but in no event later than September 1, 2021). Holders who convert shares of the Series B Preferred Stock during that period will also receive a make-whole dividend amount comprised of a fundamental change dividend make-whole amount, and to the extent there is any, the accumulated dividend amount. Because each depositary share represents a 1/20th fractional interest in a share of the Series B Preferred Stock, a holder of depositary shares may convert its depositary shares upon a fundamental change only in lots of 20 depositary shares.

Ranking. The Series B Preferred Stock, with respect to anticipated dividends and distributions upon CenterPoint Energy’s liquidation or dissolution, or winding-up of CenterPoint Energy’s affairs, ranks or will rank:

• senior to Common Stock and to each other class or series of capital stock established after the initial issue date of the Series B Preferred Stock that is expressly made subordinated to the Series B Preferred Stock;

• on a parity with the Series A Preferred Stock and any class or series of capital stock established after the initial issue date that is not expressly made senior or subordinated to the Series B Preferred Stock;

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• junior to any class or series of capital stock established after the initial issue date that is expressly made senior to the Series B Preferred Stock;

• junior to all existing and future indebtedness (including indebtedness outstanding under CenterPoint Energy’s credit facilities, senior notes and commercial paper) and other liabilities with respect to assets available to satisfy claims against CenterPoint Energy; and

• structurally subordinated to any existing and future indebtedness and other liabilities of CenterPoint Energy’s subsidiaries and capital stock of CenterPoint Energy’s subsidiaries held by third parties.

Voting Rights. Holders of the Series B Preferred Stock generally will not have voting rights. Whenever dividends on shares of the Series B Preferred Stock have not been declared and paid for six or more dividend periods (including, for the avoidance of doubt, the dividend period beginning on, and including, the initial issue date and ending on, but excluding, December 1, 2018), whether or not consecutive, the holders of such shares of Series B Preferred Stock, voting together as a single class with holders of any and all other series of voting preferred stock then outstanding (as defined in the Statement of Resolution for the Series B Preferred Stock), will be entitled at CenterPoint Energy’s next annual or special meeting of shareholders to vote for the election of a total of two additional members of CenterPoint Energy’s Board of Directors, subject to certain limitations. This right will terminate if and when all accumulated and unpaid dividends have been paid in full and, upon such termination, the term of office of each director so elected will terminate at such time and the number of directors on CenterPoint Energy’s Board of Directors will automatically decrease by two, subject to the revesting of such rights in the event of each subsequent nonpayment.

Common Stock

On October 1, 2018, CenterPoint Energy completed the issuance of 69,633,027 shares of Common Stock at a price of $27.25 per share, for net proceeds of $1,844 million after issuance costs. The amount issued included 9,082,568 shares of Common Stock issued pursuant to the exercise in full of the option granted to the underwriters to purchase additional shares of Common Stock.

CenterPoint Energy used the net proceeds from the Common Stock offering to fund a portion of the Merger and to pay related fees and expenses.

Undistributed Retained Earnings

As of December 31, 2019 and 2018, CenterPoint Energy’s consolidated retained earnings balance includes undistributed earnings from Enable of $-0- and $31 million, respectively.

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Accumulated Other Comprehensive Income (Loss)

Changes in accumulated comprehensive income (loss) are as follows:

	Year Ended December 31,
	2019									2018
	CenterPoint Energy			Houston Electric			CERC			CenterPoint Energy			Houston Electric			CERC
	(in millions)
Beginning Balance	$	(108	)	$	(14	)	$	5		$	(68	)	$	—		$	6
Other comprehensive income (loss) before reclassifications:
Remeasurement of pension and other postretirement plans	7			—			7			(19		)	—			1
Deferred loss from interest rate derivatives (1)	(3		)	(1		)	—			(19		)	(18		)	(1		)
Reclassified to earnings	1			—			—			—			—			—
Other comprehensive loss from unconsolidated affiliates	(1		)	—			—			—			—			—
Amounts reclassified from accumulated other comprehensive loss:
Prior service cost (2)	1			—			—			1			—			1
Actuarial losses (2)	8			—			—			6			—			—
Tax benefit (expense)	(3		)	—			(2		)	6			4			(1		)
Net current period other comprehensive income (loss)	10			(1		)	5			(25		)	(14		)	—
Adoption of ASU 2018-02	—			—			—			(15		)	—			(1		)
Ending Balance	$	(98	)	$	(15	)	$	10		$	(108	)	$	(14	)	$	5

(1) Gains and losses are reclassified from Accumulated other comprehensive income into income when the hedged transactions affect earnings. The reclassification amounts are included in Interest and other finance charges in each of the Registrant’s respective Statements of Consolidated Income. Amounts are $1 million and less than $1 million for the years ended December 31, 2019 and 2018, respectively.

(2) Amounts are included in the computation of net periodic cost and are reflected in Other, net in each of the Registrants’ respective Statements of Consolidated Income.

(14) Short-term Borrowings and Long-term Debt

	December 31, 2019					December 31, 2018
	Long-Term			Current (1)		Long-Term			Current (1)
	(in millions)
CenterPoint Energy:
ZENS due 2029 (2)	$	—		$	19	$	—		$	24
Senior notes 2.50% to 7.08% due 2020 to 2049 (3)	3,728			100		2,000			—
Variable rate term loans 2.275% to 2.56% due 2020 to 2021	1,000			500		—			—
First mortgage bonds 2.19% to 6.72% due 2022 to 2055 (4)	293			—		—			—
Pollution control bonds 5.125% due 2028 (5)	68			—		68			—
Commercial paper (6) (7)	1,901			—		—			—
Unamortized debt issuance costs	(22		)	—		(13		)	—
Unamortized discount and premium, net	(7		)	—		(2		)	—
Houston Electric debt (see details below)	4,719			231		4,258			458
CERC debt (see details below)	2,546			—		2,371			—
Other debt	18			18		—			—
Total CenterPoint Energy debt	$	14,244		$	868	$	8,682		$	482

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	December 31, 2019					December 31, 2018
	Long-Term			Current (1)		Long-Term			Current (1)
	(in millions)
Houston Electric:
First mortgage bonds 9.15% due 2021	$	102		$	—	$	102		$	—
General mortgage bonds 1.85% to 6.95% due 2021 to 2049	3,912			—		3,212			—
Restoration Bond Company:
System restoration bonds 4.243% due 2022	134			62		197			59
Bond Company II:
Transition bonds 5.302% due 2019	—			—		—			208
Bond Company III:
Transition bonds 5.234% due 2020	—			29		29			56
Bond Company IV:
Transition bonds 2.161% to 3.028% due 2020 to 2024	613			140		753			135
Unamortized debt issuance costs	(27		)	—		(24		)	—
Unamortized discount and premium, net	(15		)	—		(11		)	—
Total Houston Electric debt	$	4,719		$	231	$	4,258		$	458

	December 31, 2019					December 31, 2018
	Long-Term			Current (1)		Long-Term			Current (1)
	(in millions)
CERC (8):
Senior notes 3.55% to 6.625% due 2021 to 2047	$	2,193		$	—	$	2,193		$	—
Commercial paper (6)	377			—		210			—
Unamortized debt issuance costs	(13		)	—		(15		)	—
Unamortized discount and premium, net	(11		)	—		(17		)	—
Total CERC debt	$	2,546		$	—	$	2,371		$	—

(1) Includes amounts due or exchangeable within one year of the date noted.

(2) CenterPoint Energy’s ZENS obligation is bifurcated into a debt component and an embedded derivative component. For additional information regarding ZENS, see Note 12(b). As ZENS are exchangeable for cash at any time at the option of the holders, these notes are classified as a current portion of long-term debt.

(3) Includes $532 million of senior notes issued by VUHI and $96 million of senior notes issued by Indiana Gas. The senior notes have stated interest rates that range from 3.72% to 7.08%. The senior notes issued by VUHI are guaranteed by SIGECO, Indiana Gas and VEDO. In connection with the Merger, two of CenterPoint Energy’s acquired wholly-owned subsidiaries, VUHI and VCC, made offers to prepay certain outstanding guaranteed senior notes as required pursuant to certain note purchase agreements previously entered into by VUHI and VCC. In turn, VUHI and VCC borrowed $568 million and $191 million, respectively, from CenterPoint Energy to fund note redemptions of senior notes effected pursuant to these prepayment offers. To fund these prepayments and payments of approximately $5 million of accrued interest, CenterPoint Energy issued approximately $764 million of commercial paper.

(4) The first mortgage bonds issued by SIGECO subject SIGECO’s properties to a lien under the related mortgage indenture.

(5) $68 million and $68 million of these series of debt were secured by general mortgage bonds of Houston Electric as of December 31, 2019 and 2018, respectively. These general mortgage bonds are not reflected in Houston Electric’s consolidated financial statements because of the contingent nature of the obligations.

(6) Classified as long-term debt because the termination date of the facility that backstops the commercial paper is more than one year from the date noted.

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(7) Commercial paper issued by VUHI has maturities up to 30 days.

(8) Issued by CERC Corp.

Long-term Debt

Debt Retirements. During the year ended December 31, 2019, CenterPoint Energy retired the following debt instruments:

	Retirement Date	Debt Instrument	Aggregate Principal Amount		Interest Rate	Maturity Date
			(in millions)
CenterPoint Energy	December 2019	Guaranteed senior notes	$	3	3.33%	2022
CenterPoint Energy	December 2019	Guaranteed senior notes	6		4.53%	2025

In December 2019, VCC redeemed the aggregate principal amount of its guaranteed senior notes at a redemption price equal to 100% of the principal amount thereof, plus accrued and unpaid interest thereon to but excluding the redemption date, plus the make-whole premium.  The make-whole premium associated with the two redemptions was approximately $1 million and was included in Other Income, net on CenterPoint Energy’s Statements of Consolidated Income.

Debt Transactions. During the year ended December 31, 2019, the following debt instruments were issued or incurred:

	Issuance Date	Debt Instrument	Aggregate Principal Amount		Interest Rate as of December 31, 2019	Maturity Date
			(in millions)
Houston Electric	January 2019	General mortgage bonds	$	700	4.25%	2049
CenterPoint Energy (1)	February 2019	Variable rate term loan	25		2.275%	2020
CenterPoint Energy	May 2019	Variable rate term loan	1,000		2.56%	2021
CenterPoint Energy	August 2019	Unsecured senior notes	500		2.50%	2024
CenterPoint Energy	August 2019	Unsecured senior notes	400		2.95%	2030
CenterPoint Energy	August 2019	Unsecured senior notes	300		3.70%	2049

(1) Draw down by VCC on its variable rate term loan.

Securitization Bonds. As of December 31, 2019, CenterPoint Energy and Houston Electric had special purpose subsidiaries consisting of the Bond Companies, which they consolidate. The 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 transition bonds or system restoration bonds and activities incidental thereto. These Securitization Bonds are payable only through the imposition and collection of “transition” or “system restoration” charges, as defined in the Texas Public Utility Regulatory Act, which are irrevocable, non-bypassable charges to provide recovery of authorized qualified costs. CenterPoint Energy and Houston Electric have no payment obligations in respect of the Securitization Bonds other than to remit the applicable transition or system restoration charges they collect as set forth in servicing agreements among Houston Electric, the Bond Companies and other parties. Each special purpose entity is the sole owner of the right to impose, collect and receive the applicable transition or system restoration charges securing the bonds issued by that entity. Creditors of CenterPoint Energy or Houston Electric have no recourse to any assets or revenues of the Bond Companies (including the transition and system restoration charges), and the holders of Securitization Bonds have no recourse to the assets or revenues of CenterPoint Energy or Houston Electric.

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Credit Facilities. The Registrants had the following revolving credit facilities as of December 31, 2019:

Execution  Date	Registrant	Size of Facility		Draw Rate of LIBOR plus (1)	Financial Covenant Limit on Debt for Borrowed Money to Capital Ratio		Debt for Borrowed Money to Capital Ratio as of December 31, 2019 (2)	Termination  Date
		(in millions)
March 3, 2016	CenterPoint Energy	$	3,300	1.500%	65%	(3)	59.0%	March 3, 2022
July 14, 2017	CenterPoint Energy (4)	400		1.125%	65%		51.6%	July 14, 2022
July 14, 2017	CenterPoint Energy (5)	200		1.250%	65%		58.0%	July 14, 2022
March 3, 2016	Houston Electric	300		1.125%	65%	(3)	50.2%	March 3, 2022
March 3, 2016	CERC	900		1.250%	65%		46.4%	March 3, 2022
	Total	$	5,100

(1) Based on credit ratings as of December 31, 2019.

(2) As defined in the revolving credit facility agreement, excluding Securitization Bonds.

(3) For CenterPoint Energy and Houston Electric, the financial covenant limit will temporarily increase from 65% to 70% if Houston Electric experiences damage from a natural disaster in its service territory and CenterPoint Energy certifies to the administrative agent that Houston Electric has incurred system restoration costs reasonably likely to exceed $100 million in a consecutive 12-month period, all or part of which Houston Electric intends to seek to recover through securitization financing. Such temporary increase in the financial covenant would be in effect from the date CenterPoint Energy delivers its certification until the earliest to occur of (i) the completion of the securitization financing, (ii) the first anniversary of CenterPoint Energy’s certification or (iii) the revocation of such certification.

(4) This credit facility was issued by VUHI, is guaranteed by SIGECO, Indiana Gas and VEDO and includes a $10 million swing line sublimit and a $20 million letter of credit sublimit. This credit facility backstops VUHI’s commercial paper program.

(5) This credit facility was issued by VCC, is guaranteed by Vectren and includes a $40 million swing line sublimit and an$80 million letter of credit sublimit.

The Registrants, as well as the subsidiaries of CenterPoint Energy discussed above, were in compliance with all financial debt covenants as of December 31, 2019.

As of December 31, 2019 and 2018, the Registrants had the following revolving credit facilities and utilization of such facilities:

	December 31, 2019								December 31, 2018
Registrant	Loans		Letters of Credit		Commercial Paper		Weighted Average Interest Rate		Loans		Letters of Credit		Commercial Paper		Weighted Average Interest Rate
	(in millions, except weighted average interest rate)
CenterPoint Energy (1)	$	—	$	6	$	1,633	1.95	%	$	—	$	6	$	—	—	%
CenterPoint Energy (2)	—		—		268		2.08	%	—		—		—		—	%
CenterPoint Energy (3)	—		—		—		—	%	—		—		—		—	%
Houston Electric	—		—		—		—	%	—		4		—		—	%
CERC	—		1		377		1.94	%	—		1		210		2.93	%
Total	$	—	$	7	$	2,278			$	—	$	11	$	210

(1) CenterPoint Energy’s outstanding commercial paper generally has maturities of 60 days or less.

(2) This credit facility was issued by VUHI and is guaranteed by SIGECO, Indiana Gas and VEDO.

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(3) This credit facility was issued by VCC and is guaranteed by Vectren.

In January 2019, CenterPoint Energy issued the following commercial paper in connection with the closing of the Merger:

Registrant	Issuance Date	Debt Instrument	Aggregate Principal Amount		Weighted Average Interest Rate
			(in millions)
CenterPoint Energy (1) (2)	January 2019	Commercial paper	$	1,660	2.88%

(1) Proceeds from these commercial paper issuances were used to fund a portion of the Merger and to pay related fees and expenses and were contributed to Vectren for its payment of its stub period cash dividend, long-term incentive payments and to fund the repayment of indebtedness of Vectren subsidiaries redeemed at the option of the holder as a result of the closing of the Merger.

(2) The commercial paper notes were issued at various times in January 2019 with maturities up to and including 90 days as of the time of issuance, and, prior to their use as described in connection with the closing of the Merger, the net proceeds of such issuances were invested in short-term investments.

Maturities.  As of December 31, 2019, maturities of long-term debt, capital leases and sinking fund requirements, excluding the ZENS obligation, are as follows:

	CenterPoint Energy (1)		Houston  Electric (1)		CERC		Securitization Bonds
	(in millions)
2020	$	831	$	231	$	—	$	231
2021	2,761		613		593		211
2022	3,302		519		376		219
2023	713		356		300		156
2024	1,184		162		—		162

(1) These maturities include Securitization Bonds principal repayments on scheduled payment dates.

Liens.  As of December 31, 2019, Houston Electric’s assets were subject to liens securing approximately $102 million of first mortgage bonds. Sinking or improvement fund and replacement fund requirements on the first mortgage bonds may be satisfied by certification of property additions. Sinking fund and replacement fund requirements for 2019, 2018 and 2017 have been satisfied by certification of property additions. The replacement fund requirement to be satisfied in 2020 is approximately $295 million, and the sinking fund requirement to be satisfied in 2020 is approximately $1.6 million. CenterPoint Energy expects Houston Electric to meet these 2020 obligations by certification of property additions.

As of December 31, 2019, Houston Electric’s assets were also subject to liens securing approximately $4.0 billion of general mortgage bonds, including approximately $68 million held in trust to secure pollution control bonds for which CenterPoint Energy is obligated. The lien of the general mortgage indenture is junior to that of the mortgage pursuant to which the first mortgage bonds are issued. Houston Electric may issue additional general mortgage bonds on the basis of retired bonds, 70% of property additions or cash deposited with the trustee. Approximately $3.7 billion of additional first mortgage bonds and general mortgage bonds could be issued on the basis of retired bonds and 70% of property additions as of December 31, 2019. Houston Electric has contractually agreed that it will not issue additional first mortgage bonds, subject to certain exceptions.

Other. As of December 31, 2019, certain financial institutions agreed to issue, from time to time, up to $50 million of letters of credit on behalf of Vectren and certain of its subsidiaries in exchange for customary fees. These agreements to issue letters of credit expire on December 31, 2020. As of December 31, 2019, such financial institutions had issued $21 million of letters of credit on behalf of Vectren and certain of its subsidiaries. 

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(15) Income Taxes

The components of the Registrant’ income tax expense (benefit) were as follows:

	Year Ended December 31,
	2019			2018			2017
	(in millions)
CenterPoint Energy
Current income tax expense:
Federal	$	48		$	89		$	32
State	21			9			9
Total current expense	69			98			41
Deferred income tax expense (benefit):
Federal	74			(25		)	(806		)
State	(5		)	73			36
Total deferred expense (benefit)	69			48			(770		)
Total income tax expense (benefit)	$	138		$	146		$	(729	)
Houston Electric
Current income tax expense:
Federal	$	84		$	109		$	70
State	20			18			19
Total current expense	104			127			89
Deferred income tax benefit:
Federal	(24		)	(38		)	(98		)
Total deferred benefit	(24		)	(38		)	(98		)
Total income tax expense (benefit)	$	80		$	89		$	(9	)
CERC - Continuing Operations
Current income tax expense (benefit):
Federal	$	—		$	(9	)	$	(31	)
State	7			—			(10		)
Total current expense (benefit)	7			(9		)	(41		)
Deferred income tax expense (benefit):
Federal	39			10			(249		)
State	(32		)	21			25
Total deferred expense (benefit)	7			31			(224		)
Total income tax expense (benefit)	$	14		$	22		$	(265	)
CERC - Discontinued Operations
Current income tax expense (benefit):
Federal	$	—		$	9		$	31
State	—			4			11
Total current expense (benefit)	—			13			42
Deferred income tax expense:
Federal	—			29			56
State	—			4			6
Total deferred expense	—			33			62
Total income tax expense	$	—		$	46		$	104

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A reconciliation of income tax expense (benefit) using the federal statutory income tax rate to the actual income tax expense and resulting effective income tax rate is as follows:

	Year Ended December 31,
	2019			2018			2017
	(in millions)
CenterPoint Energy (1) (2) (3)
Income before income taxes	$	929		$	514		$	1,063
Federal statutory income tax rate	21		%	21		%	35		%
Expected federal income tax expense	195			108			372
Increase (decrease) in tax expense resulting from:
State income tax expense, net of federal income tax	36			22			26
State valuation allowance, net of federal income tax	(4		)	11			3
State law change, net of federal income tax	(21		)	32			—
Federal income tax rate reduction	—			—			(1,113		)
Excess deferred income tax amortization	(55		)	(24		)	—
Other, net	(13		)	(3		)	(17		)
Total	(57		)	38			(1,101		)
Total income tax expense (benefit)	$	138		$	146		$	(729	)
Effective tax rate	15		%	28		%	(69		)%
Houston Electric (4) (5) (6)
Income before income taxes	$	436		$	425		$	424
Federal statutory income tax rate	21		%	21		%	35		%
Expected federal income tax expense	92			89			148
Increase (decrease) in tax expense resulting from:
State income tax expense, net of federal income tax	16			14			12
Federal income tax rate reduction	—			—			(158		)
Excess deferred income tax amortization	(21		)	(9		)	—
Other, net	(7		)	(5		)	(11		)
Total	(12		)	—			(157		)
Total income tax expense (benefit)	$	80		$	89		$	(9	)
Effective tax rate	18		%	21		%	(2		)%
CERC - Continuing Operations (7) (8) (9)
Income before income taxes	$	226		$	92		$	319
Federal statutory income tax rate	21		%	21		%	35		%
Expected federal income tax expense	47			19			112
Increase (decrease) in tax expense resulting from:
State income tax expense, net of federal income tax	(12		)	5			6
State law change, net of federal income tax	(4		)	—			—
State valuation allowance, net of federal income tax	(4		)	11			3
Federal income tax rate reduction	—			—			(396		)
Goodwill impairment	8			—			—
Excess deferred income tax amortization	(18		)	(15		)	—
Tax basis balance sheet adjustment	—			—			11
Other, net	(3		)	2			(1		)
Total	(33		)	3			(377		)
Total income tax expense (benefit)	$	14		$	22		$	(265	)
Effective tax rate	6		%	24		%	(83		)%

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	Year Ended December 31,
	2019			2018			2017
	(in millions)
CERC - Discontinued Operations (9)
Income before income taxes	$	—		$	184		$	265
Federal statutory income tax rate	—		%	21		%	35		%
Expected federal income tax expense	—			39			93
Increase in tax expense resulting from:
State income tax expense, net of federal income tax	—			7			11
Total	—			7			11
Total income tax expense	$	—		$	46		$	104
Effective tax rate	—		%	25		%	39		%

(1) Recognized a $55 million benefit for the amortization of the net regulatory EDIT liability as decreed by regulators in certain jurisdictions, a $21 million net benefit for the impact of state law changes that resulted in the remeasurement of state deferred taxes in those jurisdictions, and $4 million net benefit for the reduction in valuation allowances on certain state net operating losses that are now expected to be realized.

(2) Recognized a $32 million deferred tax expense due to state law changes that resulted in remeasurement of state deferred taxes in those jurisdictions. Also recorded an additional $11 million valuation allowance on certain state net operating loss deferred tax assets that are no longer expected to be utilized prior to expiration after the Internal Spin. These items are partially offset by $24 million of amortization of the net regulatory EDIT liability as decreed by regulators in certain jurisdictions beginning in 2018.

(3) Recognized a $1.1 billion deferred tax benefit from the remeasurement of CenterPoint Energy’s ADFIT liability as a result of the enactment of the TCJA on December 22, 2017, which reduced the U.S. corporate income tax rate from 35% to 21%.

(4) Recognized $21 million of amortization of the net regulatory EDIT liability as decreed by regulators.

(5) Recognized $9 million of amortization of the net regulatory EDIT liability as decreed by regulators in certain jurisdictions beginning in 2018.

(6) Recognized a $158 million deferred tax benefit from the remeasurement of Houston Electric’s ADFIT liability as a result of the enactment of the TCJA on December 22, 2017, which reduced the U.S. corporate income tax rate from 35% to 21%.

(7) Recognized $18 million benefit for the amortization of the net regulatory EDIT liability as decreed by regulators in certain jurisdictions, $4 million net benefit for the impact of state law changes that resulted in the remeasurement of state deferred taxes in those jurisdictions and $4 million net benefit for the reduction in valuation allowances on certain state net operating losses that are now expected to be realized.

(8) Recorded an additional $11 million valuation allowance on certain state net operating loss deferred tax assets that are no longer expected to be utilized prior to expiration after the Internal Spin. This item is partially offset by $15 million of amortization of the net regulatory EDIT liability in certain jurisdictions as decreed by regulators beginning in 2018.

(9) Recognized a $396 million deferred tax benefit from the remeasurement of CERC’s ADFIT liability as a result of the enactment of the TCJA on December 22, 2017, which reduced the U.S. corporate income tax rate from 35% to 21%. ASC 740 requires tax impacts of changes in tax laws or rates be reported in continuing operations. Therefore, CERC’s federal income tax benefit generated by the remeasurement of the ADFIT liability for Enable during 2017 and state law changes during 2016 associated with its investment in Enable are reported in continuing operations on CERC’s Statements of Consolidated Income. The ADFIT liability associated with CERC’s investment in Enable is reported as discontinued operations on CERC’s Consolidated Balance Sheets. 

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The tax effects of temporary differences that give rise to significant portions of deferred tax assets and liabilities were as follows:

	December 31,
	2019			2018
	(in millions)
CenterPoint Energy
Deferred tax assets:
Benefits and compensation	$	152		$	160
Regulatory liabilities	447			356
Loss and credit carryforwards	111			84
Asset retirement obligations	89			62
Indexed debt securities derivative	34			—
Other	40			29
Valuation allowance	(25		)	(18		)
Total deferred tax assets	848			673
Deferred tax liabilities:
Property, plant and equipment	2,656			1,894
Investment in unconsolidated affiliates	1,010			987
Regulatory assets	344			395
Investment in marketable securities and indexed debt	586			478
Indexed debt securities derivative	—			27
Other	180			131
Total deferred tax liabilities	4,776			3,912
Net deferred tax liabilities	$	3,928		$	3,239
Houston Electric
Deferred tax assets:
Regulatory liabilities	$	195		$	205
Benefits and compensation	14			17
Asset retirement obligations	9			7
Other	7			12
Total deferred tax assets	225			241
Deferred tax liabilities:
Property, plant and equipment	1,129			1,087
Regulatory assets	126			177
Total deferred tax liabilities	1,255			1,264
Net deferred tax liabilities	$	1,030		$	1,023
CERC - Continuing Operations
Deferred tax assets:
Benefits and compensation	$	24		$	27
Regulatory liabilities	144			150
Loss and credit carryforwards	183			259
Asset retirement obligations	80			54
Other	23			20
Valuation allowance	(15		)	(18		)
Total deferred tax assets	439			492
Deferred tax liabilities:
Property, plant and equipment	821			773
Regulatory assets	45			41
Other	43			84
Total deferred tax liabilities	909			898
Net deferred tax liabilities	$	470		$	406

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Merger with Vectren. On Merger Date, pursuant to the Merger Agreement, CenterPoint Energy consummated the Merger and acquired Vectren for approximately $6 billion in cash. On the Merger Date, Vectren became a wholly-owned subsidiary of CenterPoint Energy which triggered an ownership change under Section 382 of the Code. Under this Code section, future utilization of acquired net operating loss carry forwards and other tax attributes can be limited. On the Merger Date, Vectren estimated $177 million and $60 million of federal net operating loss and of charitable contribution carryforwards, respectively, the utilization of which is not expected to be limited under Section 382.

Tax Attribute Carryforwards and Valuation Allowance.  CenterPoint Energy has no federal net operating loss carryforwards as of December 31, 2019. Also, CenterPoint Energy has $26 million of federal charitable contribution carryforwards, which have a five-year carryover period. As of December 31, 2019, CenterPoint Energy had $699 million of state net operating loss carryforwards that expire between 2020 and 2039 and $21 million of state tax credits that do not expire. CenterPoint Energy reported a valuation allowance of $25 million because it is more likely than not that the benefit from certain state net operating loss carryforwards will not be realized.

CERC has $618 million of federal net operating loss carryforwards which have an indefinite carryforward period. CERC has $691 million of state net operating loss carryforwards which expire between 2020 and 2039 and $17 million of state tax credits which do not expire. CERC reported a valuation allowance of $15 million since it is more likely than not that the benefit from certain state net operating loss carryforwards will not be realized.

A reconciliation of CenterPoint Energy’s beginning and ending balance of unrecognized tax benefits, excluding interest and penalties, for 2019 is as follows:

	Year Ended December 31, 2019
	(in millions)
Balance, beginning of year	$	—
Unrecognized tax benefits assumed through the Merger	9
Decreases related to tax positions of prior years	(1		)
Balance, end of year	$	8

CenterPoint Energy had no unrecognized tax benefits for 2018 and 2017.

During the year ended December 31, 2019, CenterPoint Energy acquired $9 million of unrecognized tax benefits in connection with the Merger. Included in the balance of uncertain tax positions as of December 31, 2019 are $3 million of tax benefits that, if recognized, would affect the effective tax rate. The above table does not include an immaterial amount of accrued interest as of December 31, 2019. The Registrants recognize interest accrued related to unrecognized tax benefits and penalties as income tax expense. The Registrants believe that it is reasonably possible that a decrease of up to $5 million in unrecognized tax benefits may occur by the end of 2020 as a result of a lapse of statutes on older exposures and/or the filing of applications for accounting method changes. CenterPoint Energy’s net unrecognized tax benefits, including penalties and interest, were $9 million as of December 31, 2019 and are included in other non-current liabilities in the Consolidated Financial Statements.

Tax Audits and Settlements. Tax years through 2017 have been audited and settled with the IRS for CenterPoint Energy. For the 2018 and 2019 tax years, the Registrants are participants in the IRS’s Compliance Assurance Process. Legacy Vectren is not currently under audit with the IRS, and the 2017-2019 tax years are still open.

(16) Commitments and Contingencies

(a) Purchase Obligations (CenterPoint Energy and CERC)

Commitments include minimum purchase obligations related to CenterPoint Energy’s and CERC’s Natural Gas Distribution and Energy Services reportable segments and CenterPoint Energy’s Indiana Electric Integrated reportable segment. Contracts with minimum payment provisions have various quantity requirements and durations and are not classified as non-trading derivative assets and liabilities in CenterPoint Energy’s and CERC’s Consolidated Balance Sheets as of December 31, 2019 and 2018. These contracts meet an exception as “normal purchases contracts” or do not meet the definition of a derivative. Natural gas and coal supply commitments also include transportation contracts that do not meet the definition of a derivative.

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As of December 31, 2019, minimum purchase obligations are approximately:

	CenterPoint Energy		CERC
	(in millions)
2020	$	750	$	533
2021	617		432
2022	418		242
2023	335		182
2024	271		174
2025 and beyond	1,888		1,526

Indiana Electric also has other purchased power agreements that do not have minimum thresholds but do require payment when energy is generated by the provider. Costs arising from certain of these commitments are pass-through costs, generally collected dollar-for-dollar from retail customers through regulator-approved cost recovery mechanisms.

(b) AMAs (CenterPoint Energy and CERC)

CenterPoint Energy’s and CERC’s NGD has AMAs associated with their utility distribution service in Arkansas, Indiana, Louisiana, Mississippi, Oklahoma and Texas. The AMAs have varying terms, the longest of which expires in 2023. Pursuant to the provisions of the agreements, CenterPoint Energy’s and CERC’s NGD 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 NGD 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 NGD 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 NGD and to use the released capacity for other purposes when it is not needed for CenterPoint Energy’s and CERC’s NGD. CenterPoint Energy’s and CERC’s NGD may receive compensation from the asset manager through payments made over the life of the AMAs. CenterPoint Energy’s and CERC’s NGD has an obligation to purchase their winter storage requirements that have been released to the asset manager under these AMAs.

(c) Guarantees and Product Warranties (CenterPoint Energy)

In the normal course of business, ESG enters into contracts requiring it to timely install infrastructure, operate facilities, pay vendors and subcontractors and support warranty obligations and, at times, issue payment and performance bonds and other forms of assurance in connection with these contracts.

Specific to ESG’s role as a general contractor in the performance contracting industry, as of December 31, 2019, there were 62 open surety bonds supporting future performance with an aggregate face amount of approximately $565 million. ESG’s exposure is less than the face amount of the surety bonds and is limited to the level of uncompleted work under the contracts. As of December 31, 2019, approximately 36% of the work was yet to be completed on projects with open surety bonds. Further, various subcontractors issue surety bonds to ESG. In addition to these performance obligations, ESG also warrants the functionality of certain installed infrastructure generally for one year and the associated energy savings over a specified number of years. Since ESG’s inception in 1994, CenterPoint Energy believes ESG has had a history of generally meeting its performance obligations and energy savings guarantees and its installed products operating effectively. CenterPoint Energy assessed the fair value of its obligation for such guarantees as of December 31, 2019 and no amounts were recorded on CenterPoint Energy’s Consolidated Balance Sheets.

CenterPoint Energy issues parent company level guarantees to certain vendors, customers and other commercial counterparties of ESG. These guarantees do not represent incremental consolidated obligations, but rather, represent guarantees of subsidiary obligations to allow those subsidiaries to conduct business without posting other forms of assurance. As of December 31, 2019, CenterPoint Energy, primarily through Vectren, has issued parent company level guarantees supporting ESG’s obligations. For those obligations where potential exposure can be estimated, management estimates the maximum exposure under these guarantees to be approximately $499 million as of December 31, 2019. This exposure primarily relates to energy savings guarantees on federal energy savings performance contracts. Other parent company level guarantees, certain of which do not contain a cap on potential liability, have been issued in support of federal operations and maintenance projects for which a maximum exposure cannot be estimated based on the nature of the projects. While there can be no assurance that performance under any of these parent company

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guarantees will not be required in the future, CenterPoint Energy considers the likelihood of a material amount being incurred as remote.

(d) Guarantees and Product Warranties (CenterPoint Energy and CERC)

In the normal course of business, CES trades natural gas under supply contracts and enters into natural gas related transactions under transportation, storage and other contracts. In connection with these CES business activities, CERC Corp. has issued guarantees to CES counterparties to guarantee the payment of CES obligations. While CES remains wholly-owned by CERC Corp., these guarantees do not represent incremental consolidated obligations, but rather, represent guarantees of CES’s obligations to allow CES to conduct business without posting other forms of assurance. As of December 31, 2019, the face amount of CERC Corp.’s guarantees of CES obligations was approximately $1.8 billion.

A CERC Corp. guarantee primarily has a one- or two-year term, although CERC Corp. would generally not be released from obligations incurred by CES prior to the termination of such guarantee unless the beneficiary of the guarantee affirmatively released CERC Corp. from its obligations under the guarantee. Since CERC Corp. has owned CES, CERC Corp. has not paid any amounts under any guarantees of CES obligations. While there can be no assurance that performance under any of these parent company guarantees will not be required in the future, CenterPoint Energy and CERC consider the likelihood of a material amount being incurred as remote.

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. Under the terms of the Equity Purchase Agreement, Athena Energy Services must generally use reasonable best efforts to replace existing CERC Corp. guarantees with credit support provided by a party other than CERC Corp. as of and after closing of the sale. Additionally, to the extent that CERC Corp. retains any exposure relating to the guarantees of CES obligations 90 days after closing, Athena Energy Services will pay a 3% annualized fee on such exposure, increasing by 1% on an annualized basis every three months.

CenterPoint Energy and CERC recorded no amounts on their respective Consolidated Balance Sheets as of December 31, 2019 and 2018 related to these guarantees.

(e) Legal, Environmental and Other Matters

Legal Matters

Gas Market Manipulation Cases (CenterPoint Energy and CERC). CenterPoint Energy, its predecessor, Reliant Energy, and certain of their former subsidiaries were named as defendants in a large number of lawsuits filed against numerous gas market participants in a number of federal and western state courts in connection with the operation of the natural gas markets in 2000-2002. CenterPoint Energy and its affiliates were released or dismissed from all such cases, except for one case in federal court in Nevada in which CES, a subsidiary of CERC, was a defendant. Plaintiffs in that case alleged a conspiracy to inflate Wisconsin natural gas prices in 2000-2002. In October 2018, CES reached an agreement to settle all claims against CES and CES’s claims for indemnity. During the third quarter of 2019, the federal district court issued final approval of the settlement and dismissed the case, and CES completed the required settlement payments; the settlement agreement has now become final. This settlement did not have a material adverse effect on CenterPoint Energy’s or CERC’s financial condition, results of operations or cash flows.

Minnehaha Academy (CenterPoint Energy and CERC). On August 2, 2017, a natural gas explosion occurred at the Minnehaha Academy in Minneapolis, Minnesota, resulting in the deaths of two school employees, serious injuries to others and significant property damage to the school. CenterPoint Energy, certain of its subsidiaries, including CERC, and the contractor company working in the school have been named in litigation arising out of this incident. CenterPoint Energy and CERC have reached confidential settlement agreements on all wrongful death and property damage claims and with some personal injury claimants. Additionally, CenterPoint Energy and CERC cooperated with the investigation conducted by the National Transportation Safety Board, which concluded its investigation in December 2019 and issued a report without making any recommendations. Further, CenterPoint Energy and CERC contested and reached a settlement regarding approximately $200,000 in fines imposed by the Minnesota Office of Pipeline Safety.  In early 2018, the Minnesota Occupational Safety and Health Administration concluded its investigation without any adverse findings against CenterPoint Energy or CERC. CenterPoint Energy’s and CERC’s general and excess liability insurance policies provide coverage for third party bodily injury and property damage claims. 

Litigation Related to the Merger (CenterPoint Energy). With respect to the Merger, in July 2018, seven separate lawsuits were filed against Vectren and the individual directors of Vectren’s Board of Directors in the U.S. District Court for the Southern District of Indiana. These lawsuits alleged violations of Sections 14(a) of the Exchange Act and SEC Rule 14a-9 on the grounds that the Vectren Proxy Statement filed on June 18, 2018 was materially incomplete because it omitted material information concerning the Merger. In August 2018, the seven lawsuits were consolidated, and the Court denied the plaintiffs’ request for a preliminary

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injunction. In October 2018, the plaintiffs filed their Consolidated Amended Class Action Complaint. In December 2018, two plaintiffs voluntarily dismissed their lawsuits. In September 2019, the court granted the defendants’ motion to dismiss and dismissed the remaining plaintiffs’ claims with prejudice, which the plaintiffs appealed in October 2019. The defendants believe that the allegations asserted are without merit and intend to vigorously defend themselves against the claims raised. CenterPoint Energy does not expect the ultimate outcome of this matter to have a material adverse effect on its financial condition, results of operations or cash flows.

Environmental Matters

MGP Sites. CenterPoint Energy, CERC and their predecessors operated MGPs in the past. In addition, certain of CenterPoint Energy’s subsidiaries acquired through the Merger operated MGPs in the past. The costs CenterPoint Energy or CERC, as applicable, expect to incur to fulfill their respective obligations are estimated by management using assumptions based on actual costs incurred, the timing of expected future payments and inflation factors, among others. While CenterPoint Energy and CERC have recorded all costs which they presently are obligated to incur in connection with activities at these sites, it is possible that future events may require remedial activities which are not presently foreseen, and those costs may not be subject to PRP or insurance recovery.

(i) Minnesota MGPs (CenterPoint Energy and CERC). With respect to certain Minnesota MGP sites, CenterPoint Energy and CERC have completed state-ordered remediation and continue state-ordered monitoring and water treatment. CenterPoint Energy and CERC recorded a liability as reflected in the table below for continued monitoring and any future remediation required by regulators in Minnesota.

(ii) Indiana MGPs (CenterPoint Energy). In the Indiana Gas service territory, the existence, location and certain general characteristics of 26 gas manufacturing and storage sites have been identified for which CenterPoint Energy may have some remedial responsibility. A remedial investigation/feasibility study was completed at one of the sites under an agreed upon order between Indiana Gas and the IDEM, and a Record of Decision was issued by the IDEM in January 2000. The remaining sites have been submitted to the IDEM’s VRP. CenterPoint Energy has also identified its involvement in five manufactured gas plant sites in SIGECO’s service territory, all of which are currently enrolled in the IDEM’s VRP. CenterPoint Energy is currently conducting some level of remedial activities, including groundwater monitoring at certain sites.

(iii) Other MGPs (CenterPoint Energy and CERC). In addition to the Minnesota and Indiana sites, the EPA and other regulators have investigated MGP sites that were owned or operated by CenterPoint Energy or CERC or may have been owned by one of their former affiliates.

Total costs that may be incurred in connection with addressing these sites cannot be determined at this time. The estimated accrued costs are limited to CenterPoint Energy’s and CERC’s share of the remediation efforts and are therefore net of exposures of other PRPs. The estimated range of possible remediation costs for the sites for which CenterPoint Energy and CERC believe they may have responsibility was based on remediation continuing for the minimum time frame given in the table below.

	December 31, 2019
	CenterPoint Energy		CERC
	(in millions, except years)
Amount accrued for remediation	$	12	$	7
Minimum estimated remediation costs	7		4
Maximum estimated remediation costs	51		32
Minimum years of remediation	5		30
Maximum years of remediation	50		50

The cost estimates are based on studies of a site or industry average costs for remediation of sites of similar size. The actual remediation costs will depend on the number of sites to be remediated, the participation of other PRPs, if any, and the remediation methods used.

CenterPoint Energy and CERC do not expect the ultimate outcome of these matters to have a material adverse effect on the financial condition, results of operations or cash flows of either CenterPoint Energy or CERC.

Asbestos. Some facilities owned by the Registrants or their predecessors contain or have contained asbestos insulation and other asbestos-containing materials. The Registrants are from time to time named, along with numerous others, as defendants in

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lawsuits filed by a number of individuals who claim injury due to exposure to asbestos, and the Registrants anticipate that additional claims may be asserted in the future. Although their ultimate outcome cannot be predicted at this time, the Registrants do not expect these matters, either individually or in the aggregate, to have a material adverse effect on their financial condition, results of operations or cash flows.

CCR Rule (CenterPoint Energy). In April 2015, the EPA finalized its CCR Rule, which regulates ash as non-hazardous material under the RCRA. The final rule allows beneficial reuse of ash, and the majority of the ash generated by Indiana Electric’s generating plants will continue to be reused. In July 2018, the EPA released its final CCR Rule Phase I Reconsideration which extended the deadline to October 31, 2020 for ceasing placement of ash in ponds that exceed groundwater protections standards or that fail to meet location restrictions. While the EPA Phase I Reconsideration moves forward, the existing CCR compliance obligations remain in effect. In August 2019, the EPA proposed additional amendments to its CCR Rule with respect to beneficial reuse of ash and other materials. The proposed revisions would not restrict Indiana Electric’s current beneficial reuse of its fly ash.

Indiana Electric has three ash ponds, two at the F.B. Culley facility (Culley East and Culley West) and one at the A.B. Brown facility. Under the existing CCR Rule, Indiana Electric is required to perform integrity assessments, including ground water monitoring, at its F.B. Culley and A.B. Brown generating stations. The ground water studies are necessary to determine the remaining service life of the ponds and whether a pond must be retrofitted with liners or closed in place, with bottom ash handling conversions completed. Indiana Electric’s Warrick generating unit is not included in the scope of the CCR Rule as this unit has historically been part of a larger generating station that predominantly serves an adjacent industrial facility. In March 2018, Indiana Electric began posting ground water data monitoring reports annually to its public website in accordance with the requirements of the CCR Rule. This data preliminarily 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 October 31, 2020. CenterPoint Energy plans to seek extensions available under the CCR Rule that would allow Indiana Electric to continue to use the ponds through December 31, 2023. The inability to take these extensions may result in increased and potentially significant operational costs in connection with the accelerated implementation of an alternative ash disposal system or adversely impact Indiana Electric’s future operations. Failure to comply with these requirements could also result in an enforcement proceeding including the imposition of fines and penalties. On April 24, 2019, Indiana Electric received an order from the IURC approving recovery in rates of costs associated with the closure of the Culley West pond, which has already commenced closure activities. CenterPoint Energy believes the language in the IURC order is favorable for future recovery of closure costs for Indiana Electric’s remaining ponds.

Indiana Electric continues to refine site specific estimates of closure costs. In July 2018, Indiana Electric filed a Complaint for Damages and Declaratory Relief against its insurers seeking reimbursement of defense, investigation and pond closure costs incurred to comply with the CCR Rule, and has since reached confidential settlement agreements with its insurers. The proceeds of these settlements will offset costs that have been and will be incurred to close the ponds. In March 2019, Indiana Electric entered into agreements with third parties for the excavation and beneficial reuse of the ash at the A.B. Brown ash pond. On August 14, 2019, Indiana Electric filed its petition with the IURC for recovery of costs associated with the closure of the A.B. Brown ash pond, which would include costs associated with the excavation and recycling of the ponded ash. On November 4, 2019, the EPA released a pre-publication copy of proposed revisions to the CCR Rule. CenterPoint Energy will evaluate the proposals to determine potential impacts to current compliance plans for its A.B. Brown and F.B. Culley generating stations.

As of December 31, 2019, CenterPoint Energy has recorded an approximate $68 million ARO, which represents the discounted value of future cash flow estimates to close the ponds at A.B. Brown and F.B. Culley. This estimate is subject to change due to the contractual arrangements; continued assessments of the ash, closure methods, and the timing of closure; implications of Indiana Electric’s generation transition plan; changing environmental regulations; and proceeds received from the settlements in the aforementioned insurance proceeding. In addition to these removal costs, Indiana Electric also anticipates equipment purchases of between $60 million and $80 million to complete the A.B. Brown closure project.

Other Environmental. From time to time, the Registrants identify the presence of environmental contaminants during operations or on property where predecessors have conducted operations. Other such sites involving contaminants may be identified in the future. The Registrants have and expect to continue to remediate any identified sites consistent with state and federal legal obligations. From time to time, the Registrants have received notices, and may receive notices in the future, from regulatory authorities or others regarding status as a PRP in connection with sites found to require remediation due to the presence of environmental contaminants. In addition, the Registrants have been, or may be, named from time to time as defendants in litigation related to such sites. Although the ultimate outcome of such matters cannot be predicted at this time, the Registrants do not expect these matters, either individually or in the aggregate, to have a material adverse effect on their financial condition, results of operations or cash flows.

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Other Proceedings

The Registrants are involved in other legal, environmental, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business. From time to time, the Registrants are also defendants in legal proceedings with respect to claims brought by various plaintiffs against broad groups of participants in the energy industry. Some of these proceedings involve substantial amounts. The Registrants regularly analyze current information and, as necessary, provide accruals for probable and reasonably estimable liabilities on the eventual disposition of these matters. The Registrants do not expect the disposition of these matters to have a material adverse effect on the Registrants’ financial condition, results of operations or cash flows.

(17) Earnings Per Share (CenterPoint Energy)

The following table reconciles numerators and denominators of CenterPoint Energy’s basic and diluted earnings per common share. Basic earnings per common share is determined by dividing Income available to common shareholders - basic by the Weighted average common shares outstanding - basic for the applicable period. Diluted earnings per common share is determined by the inclusion of potentially dilutive common stock equivalent shares that may occur if securities to issue Common Stock were exercised or converted into Common Stock.

	For the Year Ended December 31,
	2019		2018		2017
	(in millions, except per share and share amounts)
Numerator:
Income available to common shareholders - basic (1)	$	674	$	333	$	1,792
Add back: Series B Preferred Stock dividend (2)	—		—		—
Income available to common shareholders - diluted (1)	$	674	$	333	$	1,792
Denominator:
Weighted average common shares outstanding - basic	502,050,000		448,829,000		430,964,000
Plus: Incremental shares from assumed conversions:
Restricted stock (3)	3,107,000		3,636,000		3,344,000
Series B Preferred Stock (2)	—		—		—
Weighted average common shares outstanding - diluted	505,157,000		452,465,000		434,308,000
Earnings per common share:
Basic earnings per common share	$	1.34	$	0.74	$	4.16
Diluted earnings per common share	$	1.33	$	0.74	$	4.13

(1) Income available to common shareholders for the year ended December 31, 2019 includes net income from businesses acquired in the Merger of $190 million. See Note 4. Income available to common shareholders for the year ended December 31, 2017 includes a reduction in income tax expense of $1,113 million due to tax reform. See Note 15 for further discussion of the impacts of the TCJA.

(2) The potentially dilutive impact from Series B Preferred Stock applies the if-converted method in calculating diluted earnings per common share. Under this method, diluted earnings per common share is adjusted for the more dilutive effect of the Series B Preferred Stock as a result of either its accumulated dividend for the period in the numerator or the assumed-converted common share equivalent in the denominator. The computation of diluted earnings per common share outstanding for the year ended December 31, 2019 and December 31, 2018 excludes Series B Stock Dividends of $68 million and $17 million, respectively, and 34,354,000 and 8,885,000 potentially dilutive shares, respectively, because to include them would be anti-dilutive. However, these shares could be potentially dilutive in the future.

(3) The potentially dilutive impact from restricted stock awards applies the treasury stock method. Under this method, an increase in the average fair market value of Common Stock can result in a greater dilutive impact from these securities.

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(18) Unaudited Quarterly Information

Summarized quarterly financial data is as follows:

	Year Ended December 31, 2019
	First Quarter		Second Quarter		Third Quarter			Fourth Quarter
	(in millions, except per share amounts)
CenterPoint Energy
Revenues	$	3,531	$	2,798	$	2,742		$	3,230
Operating income	245		287		392			302
Income available to common shareholders	140		165		241			128
Basic earnings per common share (1)	0.28		0.33		0.48			0.25
Diluted earnings per common share (1)	0.28		0.33		0.47			0.25
Houston Electric
Revenues	686		765		859			680
Operating income	81		169		269			99
Net income	27		100		185			44
CERC
Revenues	2,368		1,342		1,126			1,734
Operating income	196		58		23			73
Net income (loss)	138		28		(7		)	53

	Year Ended December 31, 2018
	First Quarter		Second Quarter			Third Quarter			Fourth Quarter
	(in millions, except per share amounts)
CenterPoint Energy
Revenues	$	3,155	$	2,186		$	2,212		$	3,036
Operating income	251		187			226			167
Income (loss) available to common shareholders	165		(75		)	153			90
Basic earnings (loss) per common share (1)	0.38		(0.17		)	0.35			0.18
Diluted earnings (loss) per common share (1)	0.38		(0.17		)	0.35			0.18
Houston Electric
Revenues	755		854			897			728
Operating income	119		181			227			98
Net income	52		101			143			40
CERC (2)
Revenues	2,400		1,328			1,312			2,303
Operating income (loss)	131		22			(7		)	76
Income (loss) from continuing operations	78		(8		)	(35		)	35
Income (loss) from discontinued operations	52		44			44			(2		)
Net income	130		36			9			33

(1) Quarterly earnings (loss) per common share are based on the weighted average number of shares outstanding during the quarter, and the sum of the quarters may not equal annual earnings (loss) per common share.

(2) Amounts have been recast to reflect discontinued operations in all periods presented.

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(19) Reportable Segments

The Registrants’ determination of reportable segments considers the strategic operating units under which the Registrants manage sales, allocate resources and assess performance of various products and services to wholesale or retail customers in differing regulatory environments. The Registrants use operating income as the measure of profit or loss for the reportable segments other than Midstream Investments, where equity in earnings is used.

As of December 31, 2019, reportable segments by Registrant are as follows:

Registrants	Houston Electric T&D	Indiana Electric Integrated	Natural Gas Distribution	Energy Services	Infrastructure Services	Midstream Investments	Corporate and Other
CenterPoint Energy	X	X	X	X	X	X	X
Houston Electric	X
CERC			X	X			X

• CenterPoint Energy’s and Houston Electric’s Houston Electric T&D reportable segment consists of electric transmission and distribution services in the Texas Gulf Coast area.

• CenterPoint Energy’s Indiana Electric Integrated reportable segment consists of electric transmission and distribution services primarily to southwestern Indiana and includes power generation and wholesale power operations.

• CenterPoint Energy’s Natural Gas Distribution reportable segment consists of intrastate natural gas sales to, and natural gas transportation and distribution for residential, commercial, industrial and institutional customers in Arkansas, Indiana, Louisiana, Minnesota, Mississippi, Ohio, Oklahoma and Texas.

• CERC’s Natural Gas Distribution reportable segment consists of intrastate natural gas sales to, and natural gas transportation and distribution for residential, commercial, industrial and institutional customers in Arkansas, Louisiana, Minnesota, Mississippi, Oklahoma and Texas.

• CenterPoint Energy’s and CERC’s Energy Services reportable segment consists of non-rate regulated natural gas sales and services operations.

• CenterPoint Energy’s Infrastructure Services reportable segment consists of underground pipeline construction and repair services.

• CenterPoint Energy’s Midstream Investments reportable segment consists of the equity investment in Enable (excluding the Enable Series A Preferred Units).

• CenterPoint Energy’s Corporate and Other reportable segment consists of energy performance contracting and sustainable infrastructure services through ESG and other corporate operations which support all of the business operations of CenterPoint Energy.

• CERC’s Corporate and Other reportable segment consists primarily of corporate operations which support all of the business operations of CERC.

On February 3, 2020, CenterPoint Energy, through its subsidiary VUSI, entered into the Purchase Agreement to sell its Infrastructure Services reportable segment. The transaction is expected to close in the second quarter of 2020. For further information, see Notes 6 and 23 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. The transaction is expected to close in the second quarter of 2020. For further information, see Notes 6 and 23.

Expenditures for long-lived assets include property, plant and equipment. Intersegment sales are eliminated in consolidation, except as described in Note 2(b).

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Financial data for reportable segments and products and services are as follows:

CenterPoint Energy

	Revenues from External Customers			Net Intersegment Revenues			Depreciation and Amortization		Operating Income (Loss)			Total Assets				Expenditures for Long-Lived Assets
	(in millions)
As of and for the year ended December 31, 2019:
Houston Electric T&D	$	2,996	(1)	$	—		$	648	$	624		$	11,264			$	1,033
Indiana Electric Integrated	523			—			91		90			3,168				183
Natural Gas Distribution	3,643			40			417		408			13,903				1,098
Energy Services	3,653			129			16		32			1,301				12
Infrastructure Services	1,186		(2)	4			50		95			1,077				67
Midstream Investments (3)	—			—			—		—			2,473				—
Corporate and Other	300			—			65		(23		)	4,784			(4)	194
Eliminations	—			(173		)	—		—			(2,531		)		—
Consolidated	$	12,301		$	—		$	1,287	$	1,226		$	35,439			$	2,587
Reconciling items																(81		)
Capital expenditures per Statements of Consolidated Cash Flows																$	2,506
As of and for the year ended December 31, 2018:
Houston Electric T&D	$	3,232	(1)	$	—		$	917	$	623		$	10,509			$	952
Natural Gas Distribution	2,931			36			277		266			6,956				638
Energy Services	4,411			110			16		(47		)	1,558				20
Midstream Investments (3)	—			—			—		—			2,482				—
Corporate and Other	15			—			33		(11		)	6,156			(4)	110
Eliminations	—			(146		)	—		—			(652		)		—
Consolidated	$	10,589		$	—		$	1,243	$	831		$	27,009			$	1,720
Reconciling items																(69		)
Capital expenditures per Statements of Consolidated Cash Flows																$	1,651
As of and for the year ended December 31, 2017:
Houston Electric T&D	$	2,997	(1)	$	—		$	724	$	636		$	10,292			$	924
Natural Gas Distribution	2,606			33			260		348			6,608				523
Energy Services	3,997			52			19		126			1,521				11
Midstream Investments (3)	—			—			—		—			2,472				—
Corporate and Other	14			—			33		26			2,497			(4)	36
Eliminations	—			(85		)	—		—			(654		)		—
Consolidated	$	9,614		$	—		$	1,036	$	1,136		$	22,736			$	1,494
Reconciling items																(68		)
Capital expenditures per Statements of Consolidated Cash Flows																$	1,426

(1) CenterPoint Energy’s Houston Electric T&D’s revenues from major customers are as follows:

	Year Ended December 31,
	2019		2018		2017
	(in millions)
Affiliates of NRG	$	727	$	705	$	713
Affiliates of Vistra Energy Corp.	263		251		229

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(2) Includes revenues not eliminated in consolidation for pipeline construction and repair services of $162 million capitalized by CenterPoint Energy’s NGD for the 11 months ended December 31, 2019. See Note 2(b).

(3) CenterPoint Energy’s Midstream Investments’ equity earnings, net are as follows:

	Year Ended December 31,
	2019		2018		2016
	(in millions)
Enable	$	229	$	307	$	265

(4) Total assets included pension and other postemployment-related regulatory assets of $584 million, $665 million and $600 million as of December 31, 2019, 2018 and 2017, respectively. Additionally, total assets as of December 31, 2018 included $3.9 billion of temporary investments included in Cash and cash equivalents on CenterPoint Energy’s Consolidated Balance Sheets.

Houston Electric

Houston Electric consists of a single reportable segment; therefore, a tabular reportable segment presentation has not been

included.

(1) Houston Electric’s revenues from major external customers are as follows:

	Year Ended December 31,
	2019		2018		2017
	(in millions)
Affiliates of NRG	$	727	$	705	$	713
Affiliates of Vistra Energy Corp.	263		251		229

CERC

	Revenues from External Customers		Net Intersegment Revenues			Depreciation and Amortization		Operating Income (Loss)			Total Assets (1)			Expenditures for Long-Lived Assets
	(in millions)
As of and for the year ended December 31, 2019:
Natural Gas Distribution	$	2,911	$	40		$	289	$	316		$	7,497		$	773
Energy Services	3,654		128			16		32			1,301			12
Other Operations	5		—			—		2			149			—
Eliminations	—		(168		)	—		—			(508		)	—
Consolidated	$	6,570	$	—		$	305	$	350		$	8,439		$	785
Reconciling items														(9		)
Capital expenditures per Statements of Consolidated Cash Flows														$	776
As of and for the year ended December 31, 2018:
Natural Gas Distribution	$	2,931	$	36		$	277	$	266		$	6,956		$	638
Energy Services	4,411		110			16		(47		)	1,558			20
Other Operations	1		—			—		3			66			—
Eliminations	—		(146		)	—		—			(366		)	—
Consolidated	$	7,343	$	—		$	293	$	222		$	8,214		$	658
Reconciling items														(25		)
Capital expenditures per Statements of Consolidated Cash Flows														$	633

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	Revenues from External Customers		Net Intersegment Revenues			Depreciation and Amortization		Operating Income (Loss)			Total Assets (1)				Expenditures for Long-Lived Assets
	(in millions)
As of and for the year ended December 31, 2017:
Natural Gas Distribution	$	2,606	$	33		$	260	$	348		$	6,608			$	523
Energy Services	3,997		52			19		126			1,521				11
Discontinued operations	—		—			—		—			2,472			(1)	—
Other Operations	—		—			—		(7		)	70				—
Eliminations	—		(85		)	—		—			(559		)		—
Consolidated	$	6,603	$	—		$	279	$	467		$	10,112			$	534
Reconciling items															(21		)
Capital expenditures per Statements of Consolidated Cash Flows															$	513

(1) On September 4, 2018, CERC completed the Internal Spin. For further information regarding the Internal Spin, see Note 11.

	Year Ended December 31,
	2019						2018						2017
Revenues by Products and Services:	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC
	(in millions)
Electric delivery	$	3,019	$	2,990	$	—	$	3,232	$	3,234	$	—	$	2,997	$	2,998	$	—
Retail electric sales	486		—		—		—		—		—		—		—		—
Wholesale electric sales	14		—		—		—		—		—		—		—		—
Retail gas sales	4,802		—		4,070		4,161		—		4,161		3,634		—		3,634
Wholesale gas sales	2,312		—		2,313		3,008		—		3,008		2,811		—		2,811
Gas transportation and processing	33		—		33		32		—		32		29		—		29
Infrastructure services	1,186		—		—		—		—		—		—		—		—
Energy products and services	449		—		154		156		—		142		143		—		129
Total	$	12,301	$	2,990	$	6,570	$	10,589	$	3,234	$	7,343	$	9,614	$	2,998	$	6,603

(20) Supplemental Disclosure of Cash Flow Information

The tables below provide supplemental disclosure of cash flow information:

	2019						2018						2017
	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC
	(in millions)
Cash Payments/Receipts:
Interest, net of capitalized interest	$	436	$	229	$	109	$	363	$	200	$	105	$	378	$	205	$	116
Income taxes (refunds), net	155		87		7		89		154		3		15		76		4
Non-cash transactions:
Accounts payable related to capital expenditures	236		117		86		201		124		80		144		104		56
Capital distribution associated with the Internal Spin (1)	—		—		28		—		—		1,473		—		—		—
ROU assets obtained in exchange for lease liabilities (2)	44		1		29		—		—		—		—		—		—

(1) The capital distribution in 2019 associated with the Internal Spin is a result of the return to accrual for the periods of CERC’s ownership during 2018.

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(2) Includes the transition impact of adoption of ASU 2016-02 Leases as of January 1, 2019. The Registrants elected not to recast comparative periods in the year of adoption as permitted by the standard.

The table below provides a reconciliation of cash, cash equivalents and restricted cash reported in the Consolidated Balance Sheets to the amount reported in the Statements of Consolidated Cash Flows:

	December 31, 2019						December 31, 2018
	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC
	(in millions)
Cash and cash equivalents (1) (2)	$	241	$	216	$	2	$	4,231	$	335	$	14
Restricted cash included in Prepaid expenses and other current assets	30		19		—		46		34		11
Restricted cash included in Other	—		—		—		1		1		—
Total cash, cash equivalents and restricted cash shown in Statements of Consolidated Cash Flows	$	271	$	235	$	2	$	4,278	$	370	$	25

(1) CenterPoint Energy’s Cash and cash equivalents as of December 31, 2018 included $3.9 billion of temporary investments resulting from the Merger financings. CenterPoint Energy recorded interest income of $22 million, $28 million and $2 million for the years ended December 31, 2019, 2018 and 2017, respectively, in Other, net on CenterPoint Energy’s Statements of Consolidated Income. See Notes 13 and 14 for further details related to the Merger financings.

(2) Houston Electric’s Cash and cash equivalents as of December 31, 2019 and 2018 included $216 million and $335 million, respectively, of cash related to the Bond Companies. Houston Electric recorded interest income of $9 million, $4 million and $2 million for the years ended December 31, 2019, 2018 and 2017, respectively, in Other, net on Houston Electric’s Statement of Consolidated Income.

(21) Related Party Transactions (Houston Electric and CERC)

Houston Electric and CERC participate in a money pool through which they can borrow or invest on a short-term basis. Funding needs are aggregated and external borrowing or investing is based on the net cash position. The net funding requirements of the money pool are expected to be met with borrowings under CenterPoint Energy’s revolving credit facility or the sale of CenterPoint Energy’s commercial paper. 

The table below summarizes money pool activity:

	December 31, 2019						December 31, 2018
	Houston Electric			CERC			Houston Electric			CERC
	(in millions)
Money pool investments (borrowings) (1)	$	481		$	—		$	(1	)	$	114
Weighted average interest rate	1.98		%	1.98		%	2.42		%	2.42		%

(1) Included in Accounts and notes receivable (payable)–affiliated companies in Houston Electric’s and CERC’s Consolidated Balance Sheets.

Houston Electric and CERC affiliate-related net interest income (expense) were as follows:

	Year Ended December 31,
	2019				2018				2017
	Houston Electric		CERC		Houston Electric		CERC		Houston Electric		CERC
	(in millions)
Interest income (expense), net (1)	$	18	$	4	$	1	$	—	$	2	$	—

(1) Interest income is included in Other, net and interest expense is included in Interest and other finance charges on Houston Electric’s and CERC’s respective Statements of Consolidated Income.

199

CenterPoint Energy provides some corporate services to Houston Electric and CERC. The costs of services have been charged directly to Houston Electric and CERC using methods that management believes are reasonable. These methods include negotiated usage rates, dedicated asset assignment and proportionate corporate formulas based on operating expenses, assets, gross margin, employees and a composite of assets, gross margin and employees. Houston Electric provides certain services to CERC. These services are billed at actual cost, either directly or as an allocation and include fleet services, shop services, geographic services, surveying and right-of-way services, radio communications, data circuit management and field operations. Additionally, CERC provides certain services to Houston Electric. These services are billed at actual cost, either directly or as an allocation and include line locating and other miscellaneous services. These charges are not necessarily indicative of what would have been incurred had Houston Electric and CERC not been affiliates.

Infrastructure Services provides pipeline construction and repair services to CERC’s NGD. Additionally, CERC, through its subsidiary CES, sells natural gas to Indiana Electric for use in electric generation activities.

Amounts charged for these services are included primarily in Operation and maintenance expenses and amounts billed for natural gas sales are included in Non-utility revenues were as follows:

	Year Ended December 31,
	2019					2018					2017
	Houston Electric			CERC		Houston Electric			CERC		Houston Electric			CERC
	(in millions)
Corporate service charges	$	177		$	141	$	190		$	147	$	188		$	128
Net affiliate service charges (billings)	(8		)	8		(17		)	17		(9		)	9
Pipeline construction and repair service charges (1)	—			4		—			—		—			—
Natural gas sales (2)	—			1		—			—		—			—

(1) Represents charges from Infrastructure Services to CERC’s NGD for the period February 1, 2019 through December 31, 2019.

(2) Represents sales to Indiana Electric from CES for the period February 1, 2019 through December 31, 2019.

The table below presents transactions among Houston Electric, CERC and their parent, Utility Holding.

	Year Ended December 31,
	2019				2018				2017
	Houston Electric		CERC		Houston Electric		CERC		Houston Electric		CERC
	(in millions)
Cash dividends paid to parent	$	376	$	120	$	209	$	360	$	180	$	601
Cash contribution from parent	590		129		200		960		—		38
Capital distribution to parent associated with the Internal Spin (1)	—		28		—		1,473		—		—

(1) The capital distribution in 2019 associated with the Internal Spin is a result of the return to accrual for the periods of CERC’s ownership during 2018.

(22) Leases

The Registrants adopted ASC 842, Leases, and all related amendments on January 1, 2019 using the modified retrospective transition method and elected not to recast comparative periods in the year of adoption as permitted by the standard. There was no adjustment to retained earnings as a result of transition. As a result, disclosures for periods prior to adoption will be presented in accordance with accounting standards in effect for those periods. The Registrants also elected the package of practical expedients permitted under the transition guidance within the new standard, which among other things, allowed them to carry forward the historical lease classification. Additionally, the Registrants elected the practical expedient related to land easements, which allows the carry forward of the accounting treatment for land easements on existing agreements. The total ROU assets obtained in exchange for new operating lease liabilities upon adoption were $30 million, $1 million and $27 million for CenterPoint Energy, Houston Electric and CERC, respectively. The Merger was completed on February 1, 2019, and as such the amounts recorded upon adoption are exclusive of Vectren’s leases.

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An arrangement is determined to be a lease at inception based on whether the Registrant has the right to control the use of an identified asset. ROU assets represent the Registrants’ right to use the underlying asset for the lease term and lease liabilities represent the Registrants’ obligation to make lease payments arising from the lease. ROU assets and liabilities are recognized at the lease commencement date based on the present value of lease payments over the lease term, including payments at commencement that depend on an index or rate. Most leases in which the Registrants are the lessee do not have a readily determinable implicit rate, so an incremental borrowing rate, based on the information available at the lease commencement date, is utilized to determine the present value of lease payments. When a secured borrowing rate is not readily available, unsecured borrowing rates are adjusted for the effects of collateral to determine the incremental borrowing rate. Each Registrant uses the implicit rate for agreements in which it is a lessor. Lease expense and lease income are recognized on a straight-line basis over the lease term for operating leases.

The Registrants have lease agreements with lease and non-lease components and have elected the practical expedient to combine lease and non-lease components for certain classes of leases, such as office buildings. For classes of leases in which lease and non-lease components are not combined, consideration is allocated between components based on the stand-alone prices. Sublease income is not significant to the Registrants.

The Registrants’ lease agreements do not contain any material residual value guarantees, material restrictions or material covenants. There are no material lease transactions with related parties. Agreements in which the Registrants are lessors do not include provisions for the lessee to purchase the assets. Because risk is minimal, the Registrants do not take any significant actions to manage risk associated with the residual value of their leased assets.

The Registrants’ lease agreements are primarily equipment and real property leases, including land and office facility leases. The Registrants’ lease terms may include options to extend or terminate a lease when it is reasonably certain that those options will be exercised. Operating lease payments exclude approximately $16 million of legally-binding undiscounted minimum lease payments for leases signed but not yet commenced. The Registrants have elected an accounting policy that exempts leases with terms of one year or less from the recognition requirements of ASC 842.

The components of lease cost, included in Operation and maintenance expense on the Registrants’ respective Statements of Consolidated Income, are as follows:

	Year Ended December 31, 2019
	CenterPoint Energy		Houston Electric		CERC
	(in millions)
Operating lease cost	$	25	$	—	$	5
Short-term lease cost	75		23		—
Variable lease cost	1		—		1
Total lease cost	$	101	$	23	$	6

The components of lease income were as follows:

	Year Ended December 31, 2019
	CenterPoint Energy		Houston Electric		CERC
	(in millions)
Operating lease income	$	4	$	2	$	1
Variable lease income	2		—		—
Total lease income	$	6	$	2	$	1

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Supplemental balance sheet information related to leases was as follows:

	December 31, 2019
	CenterPoint Energy			Houston Electric			CERC
	(in millions, except lease term and discount rate)
Assets:
Operating ROU assets (1)	$	63		$	1		$	24
Total leased assets	$	63		$	1		$	24
Liabilities:
Current operating lease liability (2)	$	21		$	—		$	4
Non-current operating lease liability (3)	42			1			20
Total leased liabilities	$	63		$	1		$	24
Weighted-average remaining lease term (in years) - operating leases	5.1			5.2			7.7
Weighted-average discount rate - operating leases	3.42		%	3.52		%	3.67		%

(1) Reported within Other assets in the Registrants’ respective Consolidated Balance Sheets.

(2) Reported within Current other liabilities in the Registrants’ respective Consolidated Balance Sheets.

(3) Reported within Other liabilities in the Registrants’ respective Consolidated Balance Sheets.

As of December 31, 2019, maturities of operating lease liabilities were as follows:

	CenterPoint Energy		Houston  Electric		CERC
	(in millions)
2020	$	22	$	1	$	6
2021	16		—		4
2022	9		—		4
2023	7		—		3
2024	3		—		2
2025 and beyond	12		—		9
Total lease payments	69		1		28
Less: Interest	6		—		4
Present value of lease liabilities	$	63	$	1	$	24

The following table sets forth information concerning the Registrants’ obligations under non-cancelable long-term operating leases as of December 31, 2018:    

	CenterPoint Energy		Houston  Electric		CERC
	(in millions)
2019	$	6	$	1	$	5
2020	6		—		5
2021	5		—		4
2022	4		—		4
2023	3		—		3
2024 and beyond	12		—		11
Total (1)	$	36	$	1	$	32

(1) The Merger was completed on February 1, 2019. As such, these amounts are exclusive of Vectren’s leases.

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As of December 31, 2019, maturities of undiscounted operating lease payments to be received are as follows:

	CenterPoint Energy		Houston  Electric		CERC
	(in millions)
2020	$	3	$	1	$	1
2021	2		—		—
2022	2		—		—
2023	2		—		—
2024	2		—		—
2025 and beyond	10		—		—
Total lease payments to be received	$	21	$	1	$	1

Other information related to leases is as follows. See Note 20 for information on ROU assets obtained in exchange for operating lease liabilities:

	Year Ended December 31, 2019
	CenterPoint Energy		Houston Electric		CERC
	(in millions)
Operating cash flows from operating leases included in the measurement of lease liabilities	$	25	$	1	$	6

(23) Subsequent Events (CenterPoint Energy)

Proposed Divestiture of Infrastructure Services (CenterPoint Energy)

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 to PowerTeam Services. Subject to the terms and conditions of the Securities Purchase Agreement, PowerTeam Services has agreed to purchase all of the outstanding equity interests of VISCO for approximately $850 million, subject to customary adjustments set forth in the Securities Purchase Agreement, including adjustments based on VISCO’s net working capital at closing, indebtedness, cash and cash equivalents and transaction expenses. Per the Securities Purchase Agreement, VISCO will be converted from a wholly-owned corporation to a limited liability company that is disregarded for federal income tax purposes immediately prior to the closing of the transaction resulting in the sale of membership units at closing.  The sale will be considered an asset sale for tax purposes requiring the net deferred tax liabilities of approximately $123 million as of December 31, 2019 to be recognized; therefore, any deferred tax assets and liabilities within the reporting unit are not included in the carrying amount of the assets and liabilities that will be transferred to PowerTeam Services.

The completion of the sale is subject to customary closing conditions, including, among others (i) the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Act and (ii) customary conditions regarding the accuracy of the representations and warranties and compliance by the parties in all material respects with their respective obligations under the Securities Purchase Agreement. The Securities Purchase Agreement also includes customary termination provisions, including if the closing of the sale has not occurred on or before June 3, 2020. The sale is not subject to a financing condition and is expected to close in the second quarter of 2020, subject to satisfaction of the foregoing conditions, among other things.

On February18, 2020, CenterPoint Energy received notice from the Federal Trade Commission granting early termination of the waiting period under the Hart-Scott-Rodino Act in connection with the proposed sale of Infrastructure Services.

Proposed Divestiture of Energy Services (CenterPoint Energy and CERC)

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, to Athena Energy Services. This transaction does not include CEIP and its assets. Subject to the terms and conditions of the Equity Purchase Agreement, Athena Energy Services has agreed to purchase all of the outstanding equity interests of CES for approximately $400 million, subject to customary adjustments set forth in the Equity Purchase Agreement, including adjustments based on CES’s net working capital at closing, indebtedness and transaction expenses. Per the Equity Purchase Agreement, CES will be converted from a wholly-owned corporation to a limited liability company that is disregarded for federal income tax purposes immediately prior to the closing of the transaction resulting in the sale of membership units at closing. The sale will be considered an asset sale

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for tax purposes requiring the net deferred tax liabilities of approximately $25 million as of December 31, 2019 to be recognized; therefore, any deferred tax assets and liabilities within the reporting unit are not included in the carrying amount of the assets and liabilities that will be transferred to the buyer.

The completion of the sale is subject to customary closing conditions, including, among others (i) the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Act and (ii) the conversion of CES to a Delaware limited liability company, (iii) the distribution of the equity interests in CenterPoint Energy Intrastate Pipelines, LLC held by CES to CERC Corp. or its affiliates and (iv) customary conditions regarding the accuracy of the representations and warranties and compliance by the parties in all material respects with their respective obligations under the Equity Purchase Agreement. The Equity Purchase Agreement includes customary termination provisions, including if the closing of the transaction has not occurred on or before June 24, 2020.The sale is not subject to a financing condition and is expected to close in the second quarter of 2020, subject to satisfaction of the foregoing conditions, among other things.

CenterPoint Energy Dividend Declarations (CenterPoint Energy)

Equity Instrument	Declaration Date	Record Date	Payment Date	Per Share
Common Stock	February 3, 2020	February 20, 2020	March 12, 2020	$	0.2900
Series A Preferred Stock	February 3, 2020	February 14, 2020	March 2, 2020	30.6250
Series B Preferred Stock	February 3, 2020	February 14, 2020	March 2, 2020	17.5000

Enable Distributions Declarations (CenterPoint Energy)

Equity Instrument	Declaration Date	Record Date	Payment Date	Per Unit Distribution		Expected Cash Distribution
						(in millions)
Enable common units	February 7, 2020	February 18, 2020	February 25, 2020	$	0.3305	$	77
Enable Series A Preferred Units	February 7, 2020	February 7, 2020	February 14, 2020	0.6250		9

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

Disclosure Controls And Procedures

In accordance with Exchange Act Rules 13a-15 and 15d-15, the Registrants carried out separate evaluations, under the supervision and with the participation of each company’s management, including the principal executive officer and principal financial officer, of the effectiveness of the disclosure controls and procedures as of the end of the period covered by this report. Based on those evaluations, the principal executive officer and principal financial officer, in each case, concluded that the disclosure controls and procedures were effective as of December 31, 2019 to provide assurance that information required to be disclosed in the reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and such information is accumulated and communicated to management, including the principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding disclosure.

On the Merger Date, CenterPoint Energy completed the acquisition of Vectren. CenterPoint Energy evaluated the control environment and implemented CenterPoint Energy’s internal control structure over the acquired operations. With the exception of the implementation of the Vectren acquisition into CenterPoint Energy’s control structure, there has been no change in the Registrants’ internal controls over financial reporting that occurred during the three months ended December 31, 2019 that has materially affected, or is reasonably likely to materially affect, the Registrants’ internal controls over financial reporting.

204

Management’s Annual Report on Internal Control over Financial Reporting

The Registrants’ management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is defined in Rule 13a-15(f) or 15d-15(f) promulgated under the Securities Exchange Act of 1934 as a process designed by, or under the supervision of, the company’s principal executive and principal financial officers and effected by the company’s board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles and includes those policies and procedures that:

• Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the company;

• Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and

• Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements.

Management has designed its internal control over financial reporting to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with accounting principles generally accepted in the United States of America. Management’s assessment included review and testing of both the design effectiveness and operating effectiveness of controls over all relevant assertions related to all significant accounts and disclosures in the financial statements.

All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Under the supervision and with the participation of the Registrants’ management, including their respective principal executive officers and principal financial officers, the Registrants conducted an evaluation of the effectiveness of their internal control over financial reporting based on the framework in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the Registrants’ evaluation under the framework in Internal Control — Integrated Framework (2013), the Registrants’ management has concluded, in each case, that their internal control over financial reporting was effective as of December 31, 2019.

Deloitte & Touche LLP, CenterPoint Energy’s independent registered public accounting firm, has issued an attestation report on the effectiveness of CenterPoint Energy’s internal control over financial reporting as of December 31, 2019 which is set forth below. This report is not applicable to Houston Electric or CERC as they are not accelerated or large accelerated filers.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

CenterPoint Energy, Inc.

Houston, Texas

Opinion on Internal Control over Financial Reporting

 We have audited the internal control over financial reporting of CenterPoint Energy, Inc. and subsidiaries (the “Company”) as of December 31, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2019, of the Company and our report dated February 27, 2020, expressed an unqualified opinion on those financial statements.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

February 27, 2020

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Item 9B. Other Information

Compensatory Arrangements of Certain Officers

Amendments to Forms of Award Agreements under Long-Term Incentive Plan

On February 18, 2020, the Compensation Committee (“Compensation Committee”) of the Board of Directors of CenterPoint Energy approved new forms of award agreements under CenterPoint Energy’s LTIP for performance awards and restricted stock unit awards.

Among other things, the newly approved forms of award agreements for officers and director-level employees provide that a “retirement eligible” (age 55 or greater with at least five years of service) participant, who meets the requirements for enhanced retirement as specified under the agreement will fully vest in the award, subject, in the case of performance awards, to the achievement of the relevant performance metrics. The requirements for enhanced retirement for employees who are not officers subject to Section 16 of the Exchange Act include having a sum of age and years of employment equal to 65 or greater, providing at least six months’ written notice of retirement, providing a transition plan, and retiring on or after the January 1 immediately following the grant (for restricted stock units) or the first anniversary of the beginning of the designated performance cycle (for performance awards). For officers subject to Section 16 of the Exchange Act, the requirements for enhanced retirement include having a sum of age and years of employment equal to 65 or greater, providing a transition plan, providing reasonable advanced written notice of retirement (as determined by the Compensation Committee), and retiring on or after the January 1 immediately following the grant (for restricted stock units) or the first anniversary of the beginning of the designated performance cycle (for performance awards). In addition, for officers subject to Section 16 of the Exchange Act, eligibility for enhanced retirement is subject to approval by the Compensation Committee.

The newly approved forms of award agreements also provide for pro-rata vesting upon the “sale of subsidiary,” defined as a change in the ownership of a subsidiary, or a substantial portion of the assets of a subsidiary, of CenterPoint Energy, Inc., if the participant is performing services for the subsidiary at the time and ceases employment with CenterPoint Energy upon and in connection with the sale. Amounts vested upon a sale of subsidiary are paid no later than the 70^th day after the sale.

The description of the forms of award agreements, as amended, is qualified in its entirety by reference to the full text of the forms of performance award and restricted stock unit award agreements, as applicable, which are included as Exhibits 10(q)(2), 10(q)(5) and 10(q)(6) hereto and incorporated by reference herein.

Compensatory Arrangements of Certain Officers

As previously disclosed, on December 9, 2019, Tracy B. Bridge, Executive Vice President and President, Electric Division of CenterPoint Energy, provided notice of his intent to retire from CenterPoint Energy. On February 24, 2020, the Compensation Committee elected to pay Mr. Bridge pursuant to the enhanced retirement provisions under the applicable award agreements under CenterPoint Energy’s LTIP in connection with his retirement from CenterPoint Energy effective as of February 25, 2020, whereby his outstanding awards will fully vest, subject, in the case of performance awards, to the achievement of the relevant performance metrics.

On February 26, 2020, the Compensation Committee approved certain compensation arrangements for Milton Carroll, Executive Chairman of CenterPoint Energy, as a result of his increased responsibilities in connection with the previously disclosed resignation of CenterPoint Energy’s President and Chief Executive Officer. Specifically, his increased responsibilities include facilitating the identification, selection and transition of a new President and Chief Executive Officer of CenterPoint Energy. In addition to his base salary of $820,000, effective as of April 1, 2020, and long-term incentive compensation target of 325% of base salary, Mr. Carroll will receive (i) a fully-vested equity award with a value at grant equal to $1,500,000, to be granted upon the appointment of a new President and Chief Executive Officer of CenterPoint Energy, with one-third of the underlying shares to be paid upon the grant date, another one-third to be paid upon the first anniversary of the grant date, and the remaining one-third to be paid on the second anniversary of the grant date; provided, however, if Mr. Carroll earlier separates from CenterPoint Energy such that he is neither an employee nor director, any remaining unpaid shares under the award will be payable upon his separation, and (ii) a $500,000 bonus for services rendered in 2019 in connection with CenterPoint Energy’s strategic initiatives.

PART III

Item 10. Directors, Executive Officers and Corporate Governance

For CenterPoint Energy, the information called for by Item 10, to the extent not set forth in “Executive Officers” in Item 1, will be set forth in the definitive proxy statement relating to CenterPoint Energy’s 2020 annual meeting of shareholders pursuant

207

to SEC Regulation 14A. Such definitive proxy statement relates to a meeting of shareholders involving the election of directors and the portions thereof called for by Item 10 are incorporated herein by reference pursuant to Instruction G to Form 10-K.

For Houston Electric and CERC, the information called for by Item 10 is omitted pursuant to Instruction I(2) to Form 10-K (Omission of Information by Certain Wholly-Owned Subsidiaries).

Item 11. Executive Compensation

For CenterPoint Energy, the information called for by Item 11 will be set forth in the definitive proxy statement relating to CenterPoint Energy’s 2020 annual meeting of shareholders pursuant to SEC Regulation 14A. Such definitive proxy statement relates to a meeting of shareholders involving the election of directors and the portions thereof called for by Item 11 are incorporated herein by reference pursuant to Instruction G to Form 10-K.

For Houston Electric and CERC, the information called for by Item 11 is omitted pursuant to Instruction I(2) to Form 10-K (Omission of Information by Certain Wholly-Owned Subsidiaries).

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

For CenterPoint Energy, the information called for by Item 12 will be set forth in the definitive proxy statement relating to CenterPoint Energy’s 2020 annual meeting of shareholders pursuant to SEC Regulation 14A. Such definitive proxy statement relates to a meeting of shareholders involving the election of directors and the portions thereof called for by Item 12 are incorporated herein by reference pursuant to Instruction G to Form 10-K.

For Houston Electric and CERC, the information called for by Item 12 is omitted pursuant to Instruction I(2) to Form 10-K (Omission of Information by Certain Wholly-Owned Subsidiaries).

Item 13. Certain Relationships and Related Transactions, and Director Independence

For CenterPoint Energy, the information called for by Item 13 will be set forth in the definitive proxy statement relating to CenterPoint Energy’s 2020 annual meeting of shareholders pursuant to SEC Regulation 14A. Such definitive proxy statement relates to a meeting of shareholders involving the election of directors and the portions thereof called for by Item 13 are incorporated herein by reference pursuant to Instruction G to Form 10-K. See Note 11 for information related to CenterPoint Energy’s affiliate transactions.

For Houston Electric and CERC, the information called for by Item 13 is omitted pursuant to Instruction I(2) to Form 10-K (Omission of Information by Certain Wholly-Owned Subsidiaries).

Item 14. Principal Accounting Fees and Services

For CenterPoint Energy, the information called for by Item 14 will be set forth in the definitive proxy statement relating to CenterPoint Energy’s 2020 annual meeting of shareholders pursuant to SEC Regulation 14A. Such definitive proxy statement relates to a meeting of shareholders involving the election of directors and the portions thereof called for by Item 14 are incorporated herein by reference pursuant to Instruction G to Form 10-K.

Aggregate fees billed to Houston Electric and CERC during the year ended December 31, 2019 and 2018 by their principal accounting firm, Deloitte & Touche LLP, are set forth below.

	Year Ended December 31,
	2019				2018
	Houston Electric		CERC		Houston Electric		CERC
Audit fees (1)	$	884,400	$	1,419,000	$	859,950	$	1,360,800
Audit-related fees (2)	371,500		130,500		529,000		121,000
Total audit and audit-related fees	1,255,900		1,549,500		1,388,950		1,481,800
Tax fees	—		—		—		—
All other fees	—		—		—		—
Total fees	$	1,255,900	$	1,549,500	$	1,388,950	$	1,481,800

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(1) For 2019 and 2018, amounts include fees for services provided by the principal accounting firm relating to the integrated audit of financial statements and internal control over financial reporting, statutory audits, attest services, and regulatory filings.

(2) For 2019 and 2018, includes fees for consultations concerning financial accounting and reporting standards and various agreed-upon or expanded procedures related to accounting records to comply with financial accounting or regulatory reporting matters.

Houston Electric and CERC each are not required to have, and do not have, an audit committee.

PART IV

Item 15. Exhibits and Financial Statement Schedules

(a)(1) Financial Statements.

CenterPoint Energy
Report of Independent Registered Public Accounting Firm	102
Statements of Consolidated Income for the Three Years Ended December 31, 2019	106
Statements of Consolidated Comprehensive Income for the Three Years Ended December 31, 2019	107
Consolidated Balance Sheets as of December 31, 2019 and 2018	108
Statements of Consolidated Cash Flows for the Three Years Ended December 31, 2019	110
Statements of Consolidated Changes in Equity for the Three Years Ended December 31, 2019	111
Houston Electric
Report of Independent Registered Public Accounting Firm	112
Statements of Consolidated Income for the Three Years Ended December 31, 2019	113
Statements of Consolidated Comprehensive Income for the Three Years Ended December 31, 2019	114
Consolidated Balance Sheets as of December 31, 2019 and 2018	115
Statements of Consolidated Cash Flows for the Three Years Ended December 31, 2019	116
Statements of Consolidated Changes in Equity for the Three Years Ended December 31, 2019	116
CERC
Report of Independent Registered Public Accounting Firm	118
Statements of Consolidated Income for the Three Years Ended December 31, 2019	119
Statements of Consolidated Comprehensive Income for the Three Years Ended December 31, 2019	120
Consolidated Balance Sheets as of December 31, 2019 and 2018	121
Statements of Consolidated Cash Flows for the Three Years Ended December 31, 2019	123
Statements of Consolidated Changes in Equity for the Three Years Ended December 31, 2019	124
Combined Notes to Consolidated Financial Statements	125

The financial statements of Enable Midstream Partners, LP required pursuant to Rule 3-09 of Regulation S-X are included in this filing for CenterPoint Energy as Exhibit 99.1.

(a)(2) Financial Statement Schedules for the Three Years Ended December 31, 2019.

The following schedules are omitted by the Registrants because of the absence of the conditions under which they are required or because the required information is included in the financial statements:

I, II, III, IV and V.

(a)(3) Exhibits.

See Index of Exhibits beginning on page 211, which index also includes the management contracts or compensatory plans or arrangements required to be filed as exhibits to this Form 10-K by Item 601(b)(10)(iii) of Regulation S-K.

209

Item 16. Form 10-K Summary

None.

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC AND SUBSIDIARIES

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

EXHIBITS TO THE COMBINED ANNUAL REPORT ON FORM 10-K

For Fiscal Year Ended December 31, 2019

INDEX OF EXHIBITS

Exhibits included with this report are designated by a cross (†); all exhibits not so designated are incorporated herein by reference to a prior filing as indicated. Exhibits designated by an asterisk (*) are management contracts or compensatory plans or arrangements required to be filed as exhibits to this Form 10-K by Item 601(b)(10)(iii) of Regulation S-K. The Registrants have not filed the exhibits and schedules to Exhibit 2. The Registrants hereby agree to furnish supplementally a copy of any schedule omitted from Exhibit 2 to the SEC upon request.

The agreements included as exhibits are included only to provide information to investors regarding their terms.  The agreements listed below may contain representations, warranties and other provisions that were made, among other things, to provide the parties thereto with specified rights and obligations and to allocate risk among them, and such agreements should not be relied upon as constituting or providing any factual disclosures about us, any other persons, any state of affairs or other matters.

 

Exhibit Number		Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference	CenterPoint Energy	Houston Electric	CERC
2(a)	—	Transaction Agreement dated July 21, 2004 among CenterPoint Energy, Utility Holding, LLC, NN Houston Sub, Inc., Texas Genco Holdings, Inc. (Texas Genco), HPC Merger Sub, Inc. and GC Power Acquisition LLC	CenterPoint Energy’s Form 8-K dated July 21, 2004	1-31447	10.1	X
2(b)	—	Agreement and Plan of Merger, dated as of April 21, 2018, by and among Vectren Corporation, CenterPoint Energy, Inc. and Pacer Merger Sub, Inc.	CenterPoint Energy’s Form 8-K dated April 21, 2018	1-31447	2.1	X
2(c)(1)	—	Agreement and Plan of Merger among CERC, Houston Lighting and Power Company (“HL&P”), HI Merger, Inc. and NorAm Energy Corp. (“NorAm”) dated August 11, 1996	Houston Industries’ (“HI’s”) Form 8-K dated August 11, 1996	1-7629	2			X
2(c)(2)	—	Amendment to Agreement and Plan of Merger among CERC, HL&P, HI Merger, Inc. and NorAm dated August 11, 1996	Registration Statement on Form S-4	333-11329	2(c)			X
2(d)	—	Agreement and Plan of Merger dated December 29, 2000 merging Reliant Resources Merger Sub, Inc. with and into Reliant Energy Services, Inc.	Registration Statement on Form S-3	333-54526	2			X

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Exhibit Number		Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference	CenterPoint Energy	Houston Electric	CERC
2(e)	—	Master Formation Agreement dated March 14, 2013 by and among CenterPoint Energy, Inc., OGE Energy Corp., Bronco Midstream Holdings, LLC and Bronco Midstream Holdings II, LLC.	CenterPoint Energy’s Form 8-K dated March 14, 2013	1-31447	2.1	X		X
2(f)	—	Securities Purchase Agreement, dated as of February 3, 2020, by and among Vectren Utility Services, Inc., PowerTeam Services, LLC and, solely for purposes of Section 10.17 of the Securities Purchase Agreement, Vectren Corporation	CenterPoint Energy’s Form 8-K dated February 3, 2020	1-31447	2.1	X
2(g)	—	Equity Purchase Agreement, dated as of February 24, 2020, by and between CERC Corp. and Athena Energy Services Buyer, LLC	CenterPoint Energy’s Form 8-K dated February 24, 2020	1-31447	2.1	X		X
3(a)	—	Restated Articles of Incorporation of CenterPoint Energy	CenterPoint Energy’s Form 8-K dated July 24, 2008	1-31447	3.2	X
3(b)	—	Articles of Conversion of Reliant Energy Incorporated	Houston Electric’s Form 8-K dated August 31, 2002	1-3187	3(a)		X
3(c)	—	Restated Certificate of Formation of Houston Electric	Houston Electric’s Form 10-Q for the quarter ended June 30, 2011	1-3187	3.1		X
3(d)	—	Certificate of Incorporation of RERC Corp.	CERC Form 10-K for the year ended December 31, 1997	1-13265	3(a)(1)			X
3(e)	—	Certificate of Merger merging former NorAm Energy Corp. with and into HI Merger, Inc. dated August 6, 1997	CERC Form 10-K for the year ended December 31, 1997	1-13265	3(a)(2)			X
3(f)	—	Certificate of Amendment changing the name to Reliant Energy Resources Corp.	CERC Form 10-K for the year ended December 31, 1998	1-13265	3(a)(3)			X
3(g)	—	Certificate of Amendment changing the name to CenterPoint Energy Resources Corp.	CERC Form 10-Q for the quarter ended June 30, 2003	1-13265	3(a)(4)			X
3(h)	—	Third Amended and Restated Bylaws of CenterPoint Energy	CenterPoint Energy’s Form 8-K dated February 21, 2017	1-31447	3.1	X
3(i)	—	Amended and Restated Limited Liability Company Agreement of Houston Electric	Houston Electric’s Form 10-Q for the quarter ended June 30, 2011	1-3187	3.2		X
3(j)	—	Bylaws of RERC Corp.	CERC Form 10-K for the year ended December 31, 1997	1-13265	3(b)			X
3(k)	—	Statement of Resolutions Deleting Shares Designated Series A Preferred Stock of CenterPoint Energy	CenterPoint Energy’s Form 10-K for the year ended December 31, 2011	1-31447	3(c)	X

211

Exhibit Number		Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference	CenterPoint Energy	Houston Electric	CERC
3(l)	—	Statement of Resolution Establishing Series of Shares Designated Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Stock of CenterPoint Energy	CenterPoint Energy’s Form 8-K dated August 22, 2018	1-31447	3.1	X
3(m)	—	Statement of Resolution Establishing Series of Shares designated 7.00% Series B Mandatory Convertible Preferred Stock of CenterPoint Energy	CenterPoint Energy’s Form 8-K dated September 25, 2018	1-31447	3.1	X
4(a)	—	Form of CenterPoint Energy Stock Certificate	CenterPoint Energy’s Registration Statement on Form S-4	333-69502	4.1	X
4(b)	—	Form of Certificate representing the Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Stock of CenterPoint Energy	CenterPoint Energy’s Form 8-K dated August 22, 2018	1-31447	4.1	X
4(c)	—	Form of Certificate representing the 7.00% Series B Mandatory Convertible Preferred Stock of CenterPoint Energy (included as Exhibit A to Exhibit 3(l))	CenterPoint Energy’s Form 8-K dated September 25, 2018	1-31447	4.1	X
4(d)	—	Deposit Agreement, dated as of October 1, 2018, among CenterPoint Energy and Broadridge Corporate Issuer Solutions, Inc., as Depositary, and the holders from time to time of the Depositary Receipts described therein	CenterPoint Energy’s Form 8-K dated September 25, 2018	1-31447	4.2	X
4(e)	—	Form of Depositary Receipt for the Depositary Shares (included as Exhibit A to Exhibit 4(d))	CenterPoint Energy’s Form 8-K dated September 25, 2018	1-31447	4.3	X
4(f)	—	Contribution and Registration Agreement dated December 18, 2001 among Reliant Energy, CenterPoint Energy and the Northern Trust Company, trustee under the Reliant Energy, Incorporated Master Retirement Trust	CenterPoint Energy’s Form 10-K for the year ended December 31, 2001	1-31447	4.3	X
4(g)(1)	—	Mortgage and Deed of Trust, dated November 1, 1944 between Houston Lighting and Power Company (HL&P) and Chase Bank of Texas, National Association (formerly, South Texas Commercial National Bank of Houston), as Trustee, as amended and supplemented by 20 Supplemental Indentures thereto	HL&P’s Form S-7 filed on August 25, 1977	2-59748	2(b)	X	X

212

Exhibit Number		Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference	CenterPoint Energy	Houston Electric	CERC
4(g)(2)	—	Twenty-First through Fiftieth Supplemental Indentures to Exhibit 4(g)(1)	HL&P’s Form 10-K for the year ended December 31, 1989	1-3187	4(a)(2)	X	X
4(g)(3)	—	Fifty-First Supplemental Indenture to Exhibit 4(g)(1) dated as of March 25, 1991	HL&P’s Form 10-Q for the quarter ended June 30, 1991	1-3187	4(a)	X	X
4(g)(4)	—	Fifty-Second through Fifty-Fifth Supplemental Indentures to Exhibit 4(g)(1) each dated as of March 1, 1992	HL&P’s Form 10-Q for the quarter ended March 31, 1992	1-3187	4	X	X
4(g)(5)	—	Fifty-Sixth and Fifty-Seventh Supplemental Indentures to Exhibit 4(g)(1) each dated as of October 1, 1992	HL&P’s Form 10-Q for the quarter ended September 30, 1992	1-3187	4	X	X
4(g)(6)	—	Fifty-Eighth and Fifty-Ninth Supplemental Indentures to Exhibit 4(g)(1) each dated as of March 1, 1993	HL&P’s Form 10-Q for the quarter ended March 31, 1993	1-3187	4	X	X
4(g)(7)	—	Sixtieth Supplemental Indenture to Exhibit 4(g)(1) dated as of July 1, 1993	HL&P’s Form 10-Q for the quarter ended June 30, 1993	1-3187	4	X	X
4(g)(8)	—	Sixty-First through Sixty-Third Supplemental Indentures to Exhibit 4(g)(1) each dated as of December 1, 1993	HL&P’s Form 10-K for the year ended December 31, 1993	1-3187	4(a)(8)	X	X
4(g)(9)	—	Sixty-Fourth and Sixty-Fifth Supplemental Indentures to Exhibit 4(g)(1) each dated as of July 1, 1995	HL&P’s Form 10-K for the year ended December 31, 1995	1-3187	4(a)(9)	X	X
4(h)(1)	—	General Mortgage Indenture, dated as of October 10, 2002, between CenterPoint Energy Houston Electric, LLC and JPMorgan Chase Bank, as Trustee	Houston Electric’s Form 10-Q for the quarter ended September 30, 2002	1-3187	4(j)(1)	X	X
4(h)(2)	—	Second Supplemental Indenture to Exhibit 4(h)(1), dated as of October 10, 2002	Houston Electric’s Form 10- Q for the quarter ended September 30, 2002	1-3187	4(j)(3)	X	X
4(h)(3)	—	Third Supplemental Indenture to Exhibit 4(h)(1), dated as of October 10, 2002	Houston Electric’s Form 10-Q for the quarter ended September 30, 2002	1-3187	4(j)(4)	X	X
4(h)(4)	—	Officer’s Certificates dated October 10, 2002 setting forth the form, terms and provisions of the First through Eighth Series of General Mortgage Bonds	CenterPoint Energy’s Form 10-K for the year ended December 31, 2003	1-31447	4(e)(10)	X	X

213

Exhibit Number		Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference	CenterPoint Energy	Houston Electric	CERC
4(h)(5)	—	Ninth Supplemental Indenture to Exhibit 4(h)(1), dated as of November 12, 2002	CenterPoint Energy’s Form 10-K for the year ended December 31, 2002	1-31447	4(e)(10)	X	X
4(h)(6)	—	Tenth Supplemental Indenture to Exhibit 4(h)(1), dated as of March 18, 2003	CenterPoint Energy’s Form 8-K dated March 13, 2003	1-31447	4.1	X	X
4(h)(7)	—	Officer’s Certificate dated March 18, 2003 setting forth the form, terms and provisions of the Tenth Series and Eleventh Series of General Mortgage Bonds	CenterPoint Energy’s Form 8-K dated March 13, 2003	1-31447	4.2	X	X
4(h)(8)	—	Eleventh Supplemental Indenture to Exhibit 4(h)(1), dated as of May 23, 2003	CenterPoint Energy’s Form 8-K dated May 16, 2003	1-31447	4.2	X	X
4(h)(9)	—	Officer’s Certificate dated May 23, 2003 setting forth the form, terms and provisions of the Twelfth Series of General Mortgage Bonds	CenterPoint Energy’s Form 8-K dated May 16, 2003	1-31447	4.1	X	X
4(h)(10)	—	Twentieth Supplemental Indenture to Exhibit 4(h)(1), dated as of December 9, 2008	Houston Electric’s Form 8-K dated January 6, 2009	1-3187	4.2	X	X
4(h)(11)	—	Twenty-Second Supplemental Indenture to Exhibit 4(h)(1) dated as of August 10, 2012	CenterPoint Energy’s Form 10-K for the year ended December 31, 2012	1-31447	4(e)(33)	X	X
4(h)(12)	—	Officer’s Certificate, dated August 10, 2012 setting forth the form, terms and provisions of the Twenty-Second Series of General Mortgage Bonds	CenterPoint Energy’s Form 10-K for the year ended December 31, 2012	1-31447	4(e)(34)	X	X
4(h)(13)	—	Twenty-Third Supplemental Indenture to Exhibit 4(h)(1) dated as of March 17, 2014	CenterPoint Energy’s Form 10-Q for the quarter ended March 31, 2014	1-31447	4.10	X	X
4(h)(14)	—	Officer’s Certificate, dated as of March 17, 2014, setting forth the form, terms and provisions of the Twenty-Third Series of General Mortgage Bonds	CenterPoint Energy’s Form 10-Q for the quarter ended March 31, 2014	1-31447	4.11	X	X
4(h)(15)	—	Twenty-Fourth Supplemental Indenture to Exhibit 4(h)(1) dated as of May 18, 2016	CenterPoint Energy’s Form 10-Q for the quarter ended June 30, 2016	1-31447	4.5	X	X
4(h)(16)	—	Officer’s Certificate, dated as of May 18, 2016, setting forth the form, terms and provisions of the Twenty-Fifth Series of General Mortgage Bonds	CenterPoint Energy’s Form 10-Q for the quarter ended June 30, 2016	1-31447	4.6	X	X

214

Exhibit Number		Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference	CenterPoint Energy	Houston Electric	CERC
4(h)(17)	—	Twenty-Fifth Supplemental Indenture to Exhibit 4(h)(1) dated as of August 11, 2016	CenterPoint Energy’s Form 10-Q for the quarter ended September 30, 2016	1-31447	4.5	X	X
4(h)(18)	—	Officer’s Certificate, dated as of August 11, 2016, setting forth the form, terms and provisions of the Twenty-Sixth Series of General Mortgage Bonds	CenterPoint Energy’s Form 10-Q for the quarter ended September 30, 2016	1-31447	4.6	X	X
4(h)(19)	—	Twenty-Sixth Supplemental Indenture to Exhibit 4(h)(1) dated as of January 12, 2017	CenterPoint Energy’s Form 10-K for the year ended December 31, 2016	1-31447	4(e)(41)	X	X
4(h)(20)	—	Officer’s Certificate, dated as of January 12, 2017, setting forth the form, terms and provisions of the Twenty-Seventh Series of General Mortgage Bonds	CenterPoint Energy’s Form 10-K for the year ended December 31, 2016	1-31447	4(e)(42)	X	X
4(h)(21)	—	Twenty-Seventh Supplemental Indenture to Exhibit 4(h)(1) dated as of February 28, 2018	CenterPoint Energy’s Form 10-Q for the quarter ended March 30, 2018	1-31447	4.9	X	X
4(h)(22)	—	Officer’s Certificate, dated as of February 28, 2018, setting forth the form, terms and provisions of the Twenty-Eighth Series of General Mortgage Bonds	CenterPoint Energy’s Form 10-Q for the quarter ended March 30, 2018	1-31447	4.10	X	X
4(h)(23)	—	Twenty-Eighth Supplemental Indenture to Exhibit 4(h)(1) dated as of January 15, 2019	Houston Electric’s Form 8-K dated January 10, 2019	1-3187	4.4	X	X
4(h)(24)	—	Officer’s Certificate, dated as of January 15, 2019, setting forth the form, terms and provisions of the Twenty-Ninth Series of General Mortgage Bonds	CenterPoint Energy’s Form 10-K for the year ended December 31, 2018	1-31447	4(h)(24)	X	X
4(i)(1)	—	Indenture, dated as of February 1, 1998, between Reliant Energy Resources Corp. (RERC Corp.) and Chase Bank of Texas, National Association, as Trustee	CERC Corp.’s Form 8-K dated February 5, 1998	1-13265	4.1	X		X
4(i)(2)	—	Supplemental Indenture No. 10 to Exhibit 4(i)(1), dated as of February 6, 2007, providing for the issuance of CERC Corp.’s 6.25% Senior Notes due 2037	CenterPoint Energy’s Form 10-K for the year ended December 31, 2006	1-31447	4(f)(11)	X		X
4(i)(3)	—	Supplemental Indenture No. 12 to Exhibit 4(i)(1) dated as of October 23, 2007, providing for the issuance of CERC Corp.’s 6.625% Senior Notes due 2037	CenterPoint Energy’s Form 10-Q for the quarter ended June 30, 2008	1-31447	4.9	X		X

215

Exhibit Number		Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference	CenterPoint Energy	Houston Electric	CERC
4(i)(4)	—	Supplemental Indenture No. 14 to Exhibit 4(i)(1) dated as of January 11, 2011, providing for the issuance of CERC Corp.’s 4.50% Senior Notes due 2021 and 5.85% Senior Notes due 2041	CenterPoint Energy’s Form 10-K for the year ended December 31, 2010	1-31447	4(f)(15)	X		X
4(i)(5)	—	Supplemental Indenture No. 15 to Exhibit 4(i)(1) dated as of January 20, 2011, providing for the issuance of  CERC Corp.’s 4.50% Senior Notes due 2021	CenterPoint Energy’s Form 10-K for the year ended December 31, 2010	1-31447	4(f)(16)	X		X
4(i)(6)	—	Supplemental Indenture No. 16 to Exhibit 4(i)(1) dated as of August 23, 2017, providing for the issuance of CERC Corp.’s 4.10% Senior Notes due 2047	CenterPoint Energy’s Form 10-Q for the quarter ended September 30, 2017	1-31447	4.11	X		X
4(i)(7)	—	Supplemental Indenture No. 17 to Exhibit 4(i)(1) dated as of March 28, 2018, providing for the issuance of CERC Corp.’s 3.55% Senior Notes due 2023 and 4.00% Senior Notes due 2028	CERC’s Form 10-Q for the quarter ended March 31, 2018	1-13265	4.4	X		X
4(j)(1)	—	Indenture, dated as of May 19, 2003, between CenterPoint Energy and JPMorgan Chase Bank, as Trustee	CenterPoint Energy’s Form 8-K dated May 19, 2003	1-31447	4.1	X
4(j)(2)	—	Supplemental Indenture No. 9 to Exhibit 4(j)(1), dated as of August 10, 2017, providing for the issuance of CenterPoint Energy’s 2.50% Senior Notes due 2022	CenterPoint Energy’s Form 10-Q for the quarter ended September 30, 2017	1-31447	4.9	X
4(j)(3)	—	Supplemental Indenture No. 10 to Exhibit 4(j)(1), dated as of October 5, 2018, providing for the issuance of CenterPoint Energy’s 3.60% Senior Notes due 2021, 3.85% Senior Notes due 2024 and 4.25% Senior Notes due 2028	CenterPoint Energy’s Form 10-Q for the quarter ended September 30, 2018	1-31447	4.14	X
4(j)(4)	—	Supplemental Indenture No. 11 to Exhibit 4.19, dated as of August 14, 2019, providing for the issuance of CenterPoint Energy’s 2.50% Senior Notes due 2024, 2.95% Senior Notes due 2030 and 3.70% Senior Notes due 2049	CenterPoint Energy’s Form 10-Q for the quarter ended September 30, 2019	1-31447	4.2	X
4(k)(1)	—	Subordinated Indenture dated as of September 1, 1999	Reliant Energy’s Form 8-K dated September 1, 1999	1-3187	4.1	X
4(k)(2)	—	Supplemental Indenture No. 1 dated as of September 1, 1999, between Reliant Energy and Chase Bank of Texas (supplementing Exhibit 4(k)(1) and providing for the issuance Reliant Energy’s 2% Zero-Premium Exchangeable Subordinated Notes Due 2029)	Reliant Energy’s Form 8-K dated September 15, 1999	1-3187	4.2	X

216

Exhibit Number		Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference	CenterPoint Energy	Houston Electric	CERC
4(k)(3)	—	Supplemental Indenture No. 2 dated as of August 31, 2002, between CenterPoint Energy, Reliant Energy and JPMorgan Chase Bank (supplementing Exhibit 4(k)(1))	CenterPoint Energy’s Form 8-K12B dated August 31, 2002	1-31447	4(e)	X
4(k)(4)	—	Supplemental Indenture No. 3 dated as of December 28, 2005, between CenterPoint Energy, Reliant Energy and JPMorgan Chase Bank (supplementing Exhibit 4(k)(1))	CenterPoint Energy’s Form 10-K for the year ended December 31, 2005	1-31447	4(h)(4)	X
4(l)(1)	—	$1,600,000,000 Credit Agreement dated as of March 3, 2016, among CenterPoint Energy, as Borrower, and the banks named therein	CenterPoint Energy’s Form 8-K dated March 3, 2016	1-31447	4.1	X
4(l)(2)	—	First Amendment to Amended and Restated Credit Agreement, dated as of June 16, 2017, by and among CenterPoint Energy, as Borrower, and the banks named therein	CenterPoint Energy’s Form 8-K dated June 16, 2017	1-31447	4.1	X
4(l)(3)	—	Second Amendment to Amended and Restated Credit Agreement, dated as of May 25, 2018, by and among CenterPoint Energy, as Borrower, and the banks named therein	CenterPoint Energy’s Form 8-K dated May 25, 2018	1-31447	4.1	X
4(m)(1)	—	$300,000,000 Credit Agreement dated as of March 3, 2016, among Houston Electric, as Borrower, and the banks named therein	CenterPoint Energy’s Form 8-K dated March 3, 2016	1-31447	4.2	X	X
4(m)(2)	—	First Amendment to Credit Agreement, dated as of June 16, 2017, among Houston Electric, as Borrower, and the banks named therein	CenterPoint Energy’s Form 8-K dated June 16, 2017	1-31447	4.2	X	X
4(n)(1)	—	$600,000,000 Credit Agreement dated as of March 3, 2016, among CERC Corp., as Borrower, and the banks named therein	CenterPoint Energy’s Form 8-K dated March 3, 2016	1-31447	4.3	X		X
4(n)(2)	—	First Amendment to Credit Agreement, dated as of June 16, 2017, among CERC Corp., as Borrower, and the banks named therein	CenterPoint Energy’s Form 8-K dated June 16, 2017	1-31447	4.3	X		X
4(o)	—	$400,000,000 Credit Agreement, dated as of July 14, 2017, among VUHI, as Borrower, certain Subsidiaries of VUHI, as Guarantors, and the banks named therein	Vectren’s Form 8-K dated July 17, 2017	1-15467	10.1	X
4(p)	—	$200,000,000 Credit Agreement, dated as of July 14, 2017, among VCC, as Borrower, Vectren Corporation, as Guarantor, and the banks named therein	Vectren’s Form 8-K dated July 17, 2017	1-15467	10.2	X

217

Exhibit Number		Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference	CenterPoint Energy	Houston Electric	CERC
4(q)(1)	—	Term Loan Agreement dated as of July 30, 2018, among VUHI, as Borrower, the Subsidiaries of Borrower identified herein as Guarantors and the banks named therein	Vectren’s Form 8-K dated July 30, 2018	1-15467	10.1	X
4(r)(1)	—	Term Loan Agreement dated as of September 14, 2018, among VCC, as Borrower, Vectren as Guarantor, and the banks named therein	Vectren’s Form 8-K dated September 18, 2018	1-15467	10.1	X
4(r)(2)	—	First Amendment to Term Loan Agreement, dated as of June 25, 2019, among VCC, as Borrower, Vectren as Guarantor and the banks named therein	CenterPoint Energy’s Form 10-Q for the quarter ended June 30, 2019	1-31447	4.17	X
4(s)(1)	—	$1,000,000,000 Term Loan Agreement, dated as of May 15, 2019, among CenterPoint Energy, as Borrower, Mizuho Bank, Ltd., as Administrative Agent and Lead Arranger, and the banks named therein	CenterPoint Energy’s Form 8-K dated May 15, 2019	1-31447	4.1	X
4(t)(1)	—	Mortgage and Deed of Trust dated as of April 1, 1932 between SIGECO and Bankers Trust Company, as Trustee, as amended and supplemented by 28 Supplemental Indentures thereto	Post-Effective Amendment No. 1 Form 8-K dated June 1, 1984 Form 8-K dated March 24, 1986 Form 8-K dated June 3, 1986	2-2536 2-62032 2-88923 1-3553 1-3553 1-3553	B-1, B-2 (b)(4)(ii) 4(b)(2) 4 4-A 4	X X X X X X
4(t)(2)	—	Additional Supplemental Indentures to Exhibit 4(t)(1)				X
		Date as of	File Reference	Exhibit No.
		July 1, 1985	1-3553, SIGECO’s Form 10-K for the fiscal year 1985	4-A
		November 1, 1985	1-3553, SIGECO’s Form 10-K for the fiscal year 1985	4-A
		November 15, 1986	1-3553, SIGECO’s Form 10-K for the fiscal year 1986	4-A
		January 15, 1987	1-3553, SIGECO’s Form 10-K for the fiscal year 1986	4-A
		December 15, 1987	1-3553, SIGECO’s Form 10-K for the fiscal year 1987	4-A
		December 13, 1990	1-3553, SIGECO’s Form 10-K for the fiscal year 1990	4-A
		April 1, 1993	1-3553, SIGECO’s Form 8-K dated April 13, 1993	4
		June 1, 1993	1-3553, SIGECO’s Form 8-K dated June 14, 1993	4
		May 1, 1993	1-3553, SIGECO’s Form 10-K for the fiscal year 1993	4(a)

218

Exhibit Number		Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference	CenterPoint Energy	Houston Electric	CERC
		Date as of	File Reference	Exhibit No.
		July 1, 1999	1-3553, SIGECO’s Form 10-Q for the quarter ended June 30, 1999	4(a)
		March 1, 2000	1-15467, Vectren’s Form 10-K for the year ended December 31, 2001	4.1
		August 1, 2004	1-15467, Vectren’s Form 10-K for the year ended December 31, 2004	4.1
		October 1, 2004	1-15467, Vectren’s Form 10-K for the year ended December 31, 2004	4.2
		April 1, 2005	1-15467, Vectren’s Form 10-K for the year ended December 31, 2007	4.1
		March 1, 2006	1-15467, Vectren’s Form 10-K for the year ended December 31, 2007	4.2
		December 1, 2007	1-15467, Vectren’s Form 10-K for the year ended December 31, 2007	4.3
		August 1, 2009	1-15467, Vectren’s Form 10-K for the year ended December 31, 2009	4.1
		April 1, 2013	1-15467, Vectren’s Form 8-K dated April 30, 2013	4.1
		September 1, 2014	1-15467, Vectren’s Form 8-K dated September 25, 2014	4.1
		September 1, 2015	1-15467, Vectren’s Form 8-K dated September 10, 2015	4.1
4(u)(1)	—	Indenture dated February 1, 1991 between Indiana Gas Company, Inc. and U.S Bank Trust National Association (formerly known as First Trust National Association, which was formerly known as Bank of America Illinois, which was formerly known as Continental Bank, National Association)	Indiana Gas’s Form 8-K filed February 15, 1991	1-6494	4(a)	X
4(u)(2)	—	First Supplemental Indenture to Exhibit 4(u)(1), dated as of February 15, 1991	Indiana Gas’s Form 8-K filed February 15, 1991	1-6494	4(b)	X

219

Exhibit Number		Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference	CenterPoint Energy	Houston Electric	CERC
4(u)(3)	—	Second Supplemental Indenture to Exhibit 4(u)(1), dated as of September 15, 1991	Indiana Gas’s Form 8-K filed September 25, 1991	1-6494	4(b)	X
4(u)(4)	—	Third Supplemental Indenture to Exhibit 4(u)(1), dated as of September 15, 1991	Indiana Gas’s Form 8-K filed September 25, 1991	1-6494	4(c)	X
4(u)(5)	—	Fourth Supplemental Indenture to Exhibit 4(u)(1), dated as of December 2, 1992	Indiana Gas’s Form 8-K filed December 8, 1992	1-6494	4(b)	X
4(u)(6)	—	Fifth Supplemental Indenture to Exhibit 4(u)(1), dated as of December 28, 2000	Indiana Gas’s Form 8-K filed December 27, 2000	1-6494	4	X
4(v)(1)	—	Indenture dated October 19, 2001, among VUHI, Indiana Gas, SIGECO, VEDO and U.S. Bank Trust National Association	VUHI’s Form 8-K dated October 19, 2001	1-16739	4.1	X
4(v)(2)	—	First Supplemental Indenture to Exhibit 4(v)(1), dated October 19, 2001	VUHI’s Form 8-K dated October 19, 2001	1-16739	4.2	X
4(v)(3)	—	Second Supplemental Indenture to Exhibit 4(v)(1)	VUHI’s Form 8-K dated November 29, 2001	1-16739	4.1	X
4(v)(4)	—	Third Supplemental Indenture to 4(v)(1), dated July 29, 2003	VUHI’s Form 8-K dated July 24, 2003	1-16739	4.1	X
4(v)(5)	—	Fourth Supplemental Indenture to Exhibit 4(v)(1), dated November 21, 2005	VUHI’s Form 8-K dated November 18, 2005	1-16739	4.1	X
4(v)(6)	—	Form of Fifth Supplemental Indenture to Exhibit 4(v)(1), dated October 18, 2006	VUHI’s Form 8-K dated October 16, 2006	1-16739	4.1	X
4(v)(7)	—	Sixth Supplemental Indenture to Exhibit 4(v)(1), dated March 10, 2008	VUHI’s Form 8-K dated March 10, 2008	1-16739	4.1	X
4(w)	—	Note Purchase Agreement, dated March 11, 2009, among VCC, Vectren and each of the purchasers named therein	Vectren’s Form 8-K dated March 16, 2009	1-15467	4.5	X
4(x)	—	Note Purchase Agreement, dated April 7, 2009, among VUHI, Indiana Gas, SIGECO and VEDO and the purchasers named therein	Vectren’s Form 8-K dated April 7, 2009	1-15467	4.5	X
4(y)	—	Note Purchase Agreement, dated April 5, 2011, among VUHI, Indiana Gas, SIGECO and VEDO and the purchasers named therein	Vectren’s Form 8-K dated April 8, 2011	1-15467	4.1	X
4(z)	—	Note Purchase Agreement, dated November 15, 2011, among VUHI, Indiana Gas, SIGECO and VEDO and the purchasers named therein	Vectren’s Form 8-K dated November 17, 2011	1-15467	4.1	X

220

Exhibit Number		Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference	CenterPoint Energy	Houston Electric	CERC
4(aa)	—	Note Purchase Agreement, dated December 20, 2012, among VUHI, Indiana Gas, SIGECO and VEDO and the purchasers named therein	Vectren’s Form 8-K dated December 21, 2012	1-15467	4.1	X
4(bb)	—	Note Purchase Agreement, dated August 22, 2013, among VUHI, Indiana Gas, SIGECO and VEDO and the purchasers named therein	Vectren’s Form 8-K dated August 22, 2013	1-15467	4.1	X
4(cc)	—	Note Purchase Agreement, dated June 11, 2015, among VUHI, Indiana Gas, SIGECO and VEDO and the purchasers named therein	Vectren’s Form 8-K dated June 12, 2015	1-15467	4.1	X
4(dd)	—	Note Purchase Agreement, dated June 11, 2015, between VCC, Vectren and each of the purchasers named therein	Vectren’s Form 8-K dated June 12, 2015	1-15467	4.2	X
4(ee)	—	Bond Purchase and Covenants Agreement, dated September 14, 2017, between SIGECO and PNC Bank, National Association	Vectren’s Form 8-K dated September 25, 2017	1-15467	4.1	X
4(ff)	—	Joinder and First Amendment to Bond Purchase and Covenants Agreement dated March 1, 2018 among SIGECO, the lenders party thereto and PNC Bank, National Association	Vectren’s Form 8-K dated May 3, 2018	1-15467	4.1	X
4(gg)	—	Second Amendment to Bond Purchase and Covenants Agreement dated May 1, 2018 among SIGECO, the lenders party thereto and PNC Bank, National Association	Vectren’s Form 8-K dated May 3, 2018	1-15467	4.2	X
†4(hh)	—	Description of CenterPoint Energy’s Securities				X
†4(ii)	—	Description of Houston Electric’s Securities					X
†4(jj)	—	Description of CERC’s Securities						X

Pursuant to Item 601(b)(4)(iii)(A) of Regulation S-K, the Registrants have not filed as exhibits to this Form 10-K certain long-term debt instruments, including indentures, under which the total amount of securities authorized does not exceed 10% of the total assets of the Registrants and its subsidiaries on a consolidated basis. The Registrants hereby agree to furnish a copy of any such instrument to the SEC upon request.

Exhibit Number		Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference	CenterPoint Energy	Houston Electric	CERC
*10(a)	—	CenterPoint Energy, Inc. 1991 Benefit Restoration Plan, as amended and restated effective as of February 25, 2011	CenterPoint Energy’s Form 10-Q for the quarter ended March 31, 2011	1-31447	10.3	X

221

Exhibit Number		Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference	CenterPoint Energy	Houston Electric	CERC
*10(b)(1)	—	CenterPoint Energy Benefit Restoration Plan, effective as of January 1, 2008	CenterPoint Energy’s Form 8-K dated December 22, 2008	1-31447	10.1	X
*10(b)(2)	—	First Amendment to Exhibit 10(b)(1), effective as of February 25, 2011	CenterPoint Energy’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011	1-31447	10.4	X
*10(c)	—	CenterPoint Energy 1985 Deferred Compensation Plan, as amended and restated effective January 1, 2003	CenterPoint Energy’s Form 10-Q for the quarter ended September 30, 2003	1-31447	10.1	X
*10(d)(1)	—	Amended and Restated CenterPoint Energy, Inc. 1991 Savings Restoration Plan, effective as of January 1, 2008	CenterPoint Energy’s Form 8-K dated December 22, 2008	1-31447	10.4	X
*10(d)(2)	—	First Amendment to Exhibit 10(d)(1), effective as of February 25, 2011	CenterPoint Energy’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011	1-31447	10.5	X
*10(e)(1)	—	CenterPoint Energy Savings Restoration Plan, effective as of January 1, 2008	CenterPoint Energy’s Form 8-K dated December 22, 2008	1-31447	10.3	X
*10(e)(2)	—	First Amendment to Exhibit 10(e)(1), effective as of February 25, 2011	CenterPoint Energy’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011	1-31447	10.6	X
*10(e)(3)		Second Amendment to Exhibit 10(b)(1), effective as of January 1, 2020	CenterPoint Energy’s Form 8-K dated December 9, 2019	1-31447	10.1	X
*10(f)	—	CenterPoint Energy Executive Life Insurance Plan, as amended and restated effective June 18, 2003	CenterPoint Energy’s Form 10-Q for the quarter ended September 30, 2003	1-31447	10.5	X
10(g)(1)	—	Stockholder’s Agreement dated as of July 6, 1995 between Houston Industries Incorporated and Time Warner Inc.	Schedule 13-D dated July 6, 1995	5-19351	2	X
10(g)(2)	—	Amendment to Exhibit 10(g)(1) dated November 18, 1996	HI’s Form 10-K for the year ended December 31, 1996	1-7629	10(x)(4)	X

222

Exhibit Number		Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference	CenterPoint Energy	Houston Electric	CERC
†10(h)	—	Summary of Certain Compensation Arrangements of the Executive Chairman of the Board				X
10(i)(1)	—	Master Separation Agreement entered into as of December 31, 2000 between Reliant Energy, Incorporated and Reliant Resources, Inc.	Reliant Energy’s Form 10-Q for the quarter ended March 31, 2001	1-3187	10.1	X
10(i)(2)	—	First Amendment to Exhibit 10(i)(1) effective as of February 1, 2003	CenterPoint Energy’s Form 10-K for the year ended December 31, 2002	1-31447	10(bb)(5)	X
10(i)(3)	—	Employee Matters Agreement, entered into as of December 31, 2000, between Reliant Energy, Incorporated and Reliant Resources, Inc.	Reliant Energy’s Form 10-Q for the quarter ended March 31, 2001	1-3187	10.5	X
10(i)(4)	—	Retail Agreement, entered into as of December 31, 2000, between Reliant Energy, Incorporated and Reliant Resources, Inc.	Reliant Energy’s Form 10-Q for the quarter ended March 31, 2001	1-3187	10.6	X
10(i)(5)	—	Tax Allocation Agreement, entered into as of December 31, 2000, between Reliant Energy, Incorporated and Reliant Resources, Inc.	Reliant Energy’s Form 10-Q for the quarter ended March 31, 2001	1-3187	10.8	X
10(j)(1)	—	Separation Agreement entered into as of August 31, 2002 between CenterPoint Energy and Texas Genco	CenterPoint Energy’s Form 10-K for the year ended December 31, 2002	1-31447	10(cc)(1)	X
10(j)(2)	—	Transition Services Agreement, dated as of August 31, 2002, between CenterPoint Energy and Texas Genco	CenterPoint Energy’s Form 10-K for the year ended December 31, 2002	1-31447	10(cc)(2)	X
10(j)(3)	—	Tax Allocation Agreement, dated as of August 31, 2002, between CenterPoint Energy and Texas Genco	CenterPoint Energy’s Form 10-K for the year ended December 31, 2002	1-31447	10(cc)(3)	X
*10(k)(1)	—	CenterPoint Energy, Inc. Deferred Compensation Plan, as amended and restated effective January 1, 2003	CenterPoint Energy’s Form 10-Q for the quarter ended June 30, 2003	1-31447	10.2	X
*10(k)(2)	—	First Amendment to Exhibit 10(k)(1) effective as of January 1, 2008	CenterPoint Energy’s Form 8-K dated February 20, 2008	1-31447	10.4	X
*10(l)(1)	—	CenterPoint Energy 2005 Deferred Compensation Plan, effective January 1, 2008	CenterPoint Energy’s Form 8-K dated February 20, 2008	1-31447	10.3	X
*10(l)(2)	—	Amended and Restated CenterPoint Energy 2005 Deferred Compensation Plan, effective January 1, 2009	CenterPoint Energy’s Form 10-Q for the quarter ended September 30, 2008	1-31447	10.1	X

223

Exhibit Number		Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference	CenterPoint Energy	Houston Electric	CERC
*10(m)	—	CenterPoint Energy Short Term Incentive Plan, as amended and restated effective January 1, 2019	CenterPoint Energy’s Form 10-K for the year ended December 31, 2018	1-31447	10(m)	X
*10(n)(1)	—	Amended and Restated CenterPoint Energy Stock Plan for Outside Directors	CenterPoint Energy’s Form 10-Q for the quarter ended March 31, 2018	1-31447	10.1	X
†*10(n)(2)		First Amendment to Exhibit 10(n)(1), dated as of February 19, 2020				X
10(o)	—	City of Houston Franchise Ordinance	CenterPoint Energy’s Form 10-Q for the quarter ended June 30, 2005	1-31447	10.1	X	X
10(p)(1)	—	Amended and Restated HL&P Executive Incentive Compensation Plan effective as of January 1, 1985	CenterPoint Energy’s Form 10-Q for the quarter ended September 30, 2008	1-31447	10.2	X
10(p)(2)	—	First Amendment to Exhibit 10(p)(1) effective as of January 1, 2008	CenterPoint Energy’s Form 10-Q for the quarter ended September 30, 2008	1-31447	10.3	X
*10(q)(1)	—	CenterPoint Energy, Inc. 2009 Long Term Incentive Plan	CenterPoint Energy’s Schedule 14A dated March 13, 2009	1-31447	A	X
†*10(q)(2)	—	Form of Performance Award Agreement for 20XX - 20XX Performance Cycle under Exhibit 10(q)(1)				X
*10(q)(3)	—	Form of Performance Award Agreement for Executive Chairman 20XX - 20XX Performance Cycle under Exhibit 10(q)(1)	CenterPoint Energy’s Form 10-Q for the quarter ended March 31, 2018	1-31447	10.4	X
*10(q)(4)	—	Form of Restricted Stock Unit Award Agreement (With Performance Goal) under Exhibit 10(q)(1)	CenterPoint Energy’s Form 8-K dated February 28, 2012	1-31447	10.2	X
†*10(q)(5)	—	Form of Restricted Stock Unit Award Agreement (Service-Based Vesting) under Exhibit 10(q)(1)				X
†*10(q)(6)	—	Form of Restricted Stock Unit Award Agreement (Retention, Service-Based Vesting) under Exhibit 10(q)(1)				X
*10(q)(7)	—	Form of Executive Chairman Restricted Stock Unit Award Agreement (Service-Based Vesting) under Exhibit 10(q)(1)	CenterPoint Energy’s Form 10-Q for the quarter ended March 31, 2018	1-31447	10.7	X
†10(r)	—	Summary of Non-Employee Director Compensation				X

224

Exhibit Number		Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference	CenterPoint Energy	Houston Electric	CERC
†10(s)	—	Summary of Senior Executive Officer Compensation				X
*10(t)	—	Change in Control Plan	CenterPoint Energy’s Form 8-K dated April 27, 2017	1-31447	10.1	X
*10(u)	—	Omnibus Amendment to CenterPoint Energy, Inc. Benefit Plans, dated May 23, 2013	CenterPoint Energy’s Form 10-K for the year ended December 31, 2013	1-31447	10(zz)	X
*10(v)		Vectren Non-Qualified Deferred Compensation Plan, as amended and restated effective January 1, 2001	Vectren’s Form 10-K for the year end December 31, 2001	1-15467	10.32	X
*10(w)		Vectren Corporation Non-Qualified Deferred Compensation Plan, effective January 1, 2005	Vectren’s Form 8-K dated September 29, 2008	1-15467	10.3	X
*10(x)		Vectren Nonqualified Defined Benefit Restoration Plan, as amended and restated effective January 1, 2005	Vectren’s Form 8-K dated December 17, 2008	1-15467	10.2	X
*10(y)		Vectren specimen change in control agreement dated December 31, 2011	Vectren’s Form 8-K dated January 5, 2012	1-15467	10.1	X
*10(z)		Amendment Number One to the Vectren specimen change in control agreement dated December 31, 2012	Vectren’s Form 10-K for the year end December 31, 2012	1-15467	10.1	X
*10(aa)		Vectren Unfunded Supplemental Retirement Plan for a Select Group of Management Employees (As Amended and Restated Effective January 1, 2005)	Vectren’s Form 8-K dated December 17, 2008	1-15467	10.1	X
*10(bb)		Vectren Specimen Waiver, effective October 3, 2013, to the Vectren Unfunded Supplemental Retirement Plan for a Select Group of Management Employees	Vectren’s Form 10-Q for the quarter ended September 30, 2013	1-15467	10.1	X
10(cc)	—	Master Formation Agreement, dated as of March 14, 2013, among CenterPoint Energy, OGE, Bronco Midstream Holdings, LLC and Bronco Midstream Holdings II, LLC	CenterPoint Energy’s Form 8-K dated March 14, 2013	1-31447	2.1	X
10(dd)	—	Fifth Amended and Restated Agreement of Limited Partnership of Enable Midstream Partners, LP, dated November 14, 2017	CenterPoint Energy’s Form 8-K dated November 14, 2017	1-31447	10.1	X
10(ee)	—	Third Amended and Restated Limited Liability Company Agreement of Enable GP, LLC dated June 22, 2016	CenterPoint Energy’s Form 8-K dated June 22, 2016	1-31447	10.2	X

225

Exhibit Number		Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference	CenterPoint Energy	Houston Electric	CERC
10(ff)	—	Registration Rights Agreement dated as of May 1, 2013 by and among CenterPoint Energy Field Services (CEFS), CERC Corp., OGE Enogex Holdings LLC, and Enogex Holdings LLC	CenterPoint Energy’s Form 8-K dated May 1, 2013	1-31447	10.3	X
10(gg)	—	Omnibus Agreement dated as of May 1, 2013 among CenterPoint Energy, OGE, Enogex Holdings LLC and CEFS	CenterPoint Energy’s Form 8-K dated May 1, 2013	1-31447	10.4	X
10(hh)	—	Indenture, dated as of May 27, 2014, between Enable Midstream Partners, LP and U.S. Bank National Association, as trustee	CERC’s Form 8-K dated May 27, 2014	1-13265	10.1			X
10(ii)	—	First Supplemental Indenture, dated as of May 27, 2014, among Enable Midstream Partners, LP, CenterPoint Energy Resources Corp., as guarantor, and U.S. Bank National Association, as trustee	CERC’s Form 8-K dated May 27, 2014	1-13265	10.2			X
10(jj)	—	Registration Rights Agreement, dated as of May 27, 2014, by and among Enable Midstream Partners, LP, CenterPoint Energy Resources Corp., as guarantor, and RBS Securities Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Credit Suisse Securities (USA) LLC, and RBC Capital Markets, LLC, as representatives of the initial purchasers	CERC’s Form 8-K dated May 27, 2014	1-13265	10.3			X
10(kk)	—	Purchase Agreement dated January 28, 2016, by and between Enable Midstream Partners, LP and CenterPoint Energy, Inc.	CenterPoint Energy’s Form 8-K dated January 28, 2016	1-31447	10.1	X
10(ll)	—	Registration Rights Agreement dated as of February 18, 2016 by and between Enable Midstream Partners, LP and CenterPoint Energy, Inc.	CenterPoint Energy’s Form 8-K dated February 18, 2016	1-31447	10.2	X
10(mm)	—	Commitment Letter, dated as of April 21, 2018, by Goldman Sachs Bank USA and Morgan Stanley Senior Funding, Inc. to CenterPoint Energy, Inc.	CenterPoint Energy’s Form 8-K dated April 21, 2018	1-31447	10.1	X
†21	—	Subsidiaries of CenterPoint Energy				X
†23.1	—	Consent of Deloitte & Touche LLP				X
†23.2	—	Consent of Deloitte & Touche LLP, Independent Registered Public Accounting Firm of Enable Midstream Partners, LP				X

226

Exhibit Number		Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference	CenterPoint Energy	Houston Electric	CERC
†31.1.1	—	Rule 13a-14(a)/15d-14(a) Certification of John W. Somerhalder II				X
†31.1.2	—	Rule 13a-14(a)/15d-14(a) Certification of John W. Somerhalder II					X
†31.1.3	—	Rule 13a-14(a)/15d-14(a) Certification of John W. Somerhalder II						X
†31.2.1	—	Rule 13a-14(a)/15d-14(a) Certification of Xia Liu				X
†31.2.2	—	Rule 13a-14(a)/15d-14(a) Certification of Xia Liu					X
†31.2.3	—	Rule 13a-14(a)/15d-14(a) Certification of Xia Liu						X
†32.1.1	—	Section 1350 Certification of John W. Somerhalder II				X
†32.1.2	—	Section 1350 Certification of John W. Somerhalder II					X
†32.1.3	—	Section 1350 Certification of John W. Somerhalder II						X
†32.2.1	—	Section 1350 Certification of Xia Liu				X
†32.2.2	—	Section 1350 Certification of Xia Liu					X
†32.2.3	—	Section 1350 Certification of Xia Liu						X
99.1	—	Financial Statements of Enable Midstream Partners, LP as of December 31, 2019 and 2018 and for the years ended December 31, 2019, 2018 and 2017	Part II, Item 8 of Enable Midstream Partners, LP’s Form 10-K for the year ended December 31, 2019	001-36413	Item 8	X
†101.INS	—	Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document				X	X	X
†101.SCH	—	Inline XBRL Taxonomy Extension Schema Document				X	X	X
†101.CAL	—	Inline XBRL Taxonomy Extension Calculation Linkbase Document				X	X	X
†101.DEF	—	Inline XBRL Taxonomy Extension Definition Linkbase Document				X	X	X
†101.LAB	—	Inline XBRL Taxonomy Extension Labels Linkbase Document				X	X	X
†101.PRE	—	Inline XBRL Taxonomy Extension Presentation Linkbase Document				X	X	X
†104	—	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)				X	X	X

227

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrants have duly caused this report to be signed on their behalf by the undersigned, thereunto duly authorized, in the City of Houston, the State of Texas, on the 27th day of February, 2020.

CENTERPOINT ENERGY, INC.

(Registrant)

By:  /s/ John W. Somerhalder II

John W. Somerhalder II

Interim President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on February 27, 2020.

Signature	Title
/s/  JOHN W. SOMERHALDER II	Interim President, Chief Executive Officer and
John W. Somerhalder II	Director (Principal Executive Officer and Director)
/s/  XIA LIU	Executive Vice President and Chief
Xia Liu	Financial Officer (Principal Financial Officer)
/s/  KRISTIE L. COLVIN	Senior Vice President and Chief
Kristie L. Colvin	Accounting Officer (Principal Accounting Officer)
/s/  MILTON CARROLL	Executive Chairman of the Board of Directors
Milton Carroll
/s/  LESLIE D. BIDDLE	Director
Leslie D. Biddle
/s/  SCOTT J. MCLEAN	Director
Scott J. McLean
/s/  MARTIN H. NESBITT	Director
Martin H. Nesbitt
/s/  THEODORE F. POUND	Director
Theodore F. Pound
/s/  SUSAN O. RHENEY	Director
Susan O. Rheney
/s/  PHILLIP R. SMITH	Director
Phillip R. Smith
/s/  PETER S. WAREING	Director
Peter S. Wareing

	CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC
	(Registrant)
By:	/s/ JOHN W. SOMERHALDER II
	John W. Somerhalder II
	Interim Manager

228

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on February 27, 2020.

Signature	Title
/s/ JOHN W. SOMERHALDER II	Interim Manager and Chairman
(John W. Somerhalder II)	(Principal Executive Officer)
/s/ XIA LIU	Executive Vice President and Chief Financial Officer
(Xia Liu)	(Principal Financial Officer)
/s/ KRISTIE L. COLVIN	Senior Vice President and Chief Accounting Officer
(Kristie L. Colvin)	(Principal Accounting Officer)

	CENTERPOINT ENERGY RESOURCES CORP.
	(Registrant)
By:	/s/ JOHN W. SOMERHALDER II
	John W. Somerhalder II
	President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on February 27, 2020.

Signature	Title
/s/ JOHN W. SOMERHALDER II	Interim Chairman, President and Chief Executive Officer
(John W. Somerhalder II)	(Principal Executive Officer and Director)
/s/ XIA LIU	Executive Vice President and Chief Financial Officer
(Xia Liu)	(Principal Financial Officer)
/s/ KRISTIE L. COLVIN	Senior Vice President and Chief Accounting Officer
(Kristie L. Colvin)	(Principal Accounting Officer)

229

EX-4.HH

Exhibit 4(hh)

DESCRIPTION OF CENTERPOINT ENERGY, INC.’S SECURITIES

REGISTERED PURSUANT TO SECTION 12

OF THE SECURITIES EXCHANGE ACT OF 1934

As of December 31, 2019, CenterPoint Energy, Inc. has two classes of securities registered under Section 12 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”): (1) our common stock, par value $0.01 per share and (2) our depositary shares, each representing a 1/20th interest in a share of 7.00% Series B Mandatory Convertible Preferred Stock, $0.01 par value. As used in this Exhibit 4(hh), the terms “CenterPoint Energy,” “us,” “we” or “our” refer to CenterPoint Energy, Inc. and not any of its subsidiaries.

CenterPoint Energy, Inc. is authorized to issue up to 1,000,000,000 shares of common stock, par value $0.01 per share, and 20,000,000 shares of preferred stock, par value $0.01 per share.

DESCRIPTION OF OUR COMMON STOCK

The following description of our common stock is a summary and does not purport to be complete. It is subject to and qualified in its entirety by reference to our Restated Articles of Incorporation (“Articles of Incorporation”) and Third Amended and Restated Bylaws (“Bylaws”),each of which are incorporated by reference as an exhibit to the Annual Report on Form 10-K of which this Exhibit 4(hh) is a part. We encourage you to read our Articles of Incorporation, our Bylaws and the applicable provisions of the Texas Business Organizations Code (“TBOC”) for additional information.

Voting Rights. Holders of our common stock are entitled to one vote for each share on all matters submitted to a vote of shareholders, including the election of directors. There are no cumulative voting rights. Subject to the voting rights expressly conferred to the holders of our preferred stock, the holders of our common stock possess exclusive full voting power for the election of directors and for all other purposes. Our Bylaws provide that director nominees are elected by the vote of a majority of the votes cast with respect to the director by shareholders entitled to vote at the meeting in an uncontested election. An election is contested if, at a specified time before we file our definitive proxy statement with the SEC, the number of nominees exceeds the number of directors to be elected, in which case directors will be elected by the vote of a plurality of the votes cast by shareholders entitled to vote at the meeting.

Dividends. Subject to preferences that may be applicable to any of our outstanding preferred stock, the holders of our common stock are entitled to dividends when, as and if declared by the board of directors out of funds legally available for that purpose.

Liquidation Rights. If we are liquidated, terminated or wound up, the holders of our common stock will be entitled to a pro rata share in any distribution to shareholders, but only after satisfaction of all of our liabilities and of the prior rights of any outstanding class of our preferred stock, which may include the right to participate further with the holders of our common stock in the distribution of any of our remaining assets.

Preemptive Rights. Holders of our common stock are not entitled to any preemptive or conversion rights or other subscription rights.

Transfer Agent and Registrar. Broadridge Corporate Issuer Solutions, Inc. serves as transfer agent and registrar for our common stock.

Other Provisions. There are no redemption or sinking fund provisions applicable to our common stock. No personal liability will attach to holders of such shares under the laws of the State of Texas. Subject to the provisions of our Articles of Incorporation and Bylaws imposing certain supermajority voting provisions, the rights of the holders of shares of our common stock may not be modified except by a vote of at least a majority of the shares outstanding, voting together as a single class.

Preferred Stock

Our board of directors may cause us to issue preferred stock from time to time in one or more series and may fix the number of shares and the terms of each series without the approval of our shareholders. Our board of directors may determine the terms of each series, including:

• the designation of the series,

• dividend rates and payment dates,

• whether dividends will be cumulative, non-cumulative or partially cumulative, and related terms,

• redemption rights,

• liquidation rights,

• sinking fund provisions,

• conversion rights,

• voting rights, and

• any other terms.

The prospectus supplement relating to any series of preferred stock will include specific terms relating to the offering. We will file the form of the preferred stock with the SEC before we issue any of it. The prospectus supplement for any offering of preferred stock will include some or all of the following terms:

• the title of the preferred stock,

• the maximum number of shares of the series,

• the dividend rate or the method of calculating the dividend, the date from which dividends will accrue and whether dividends will be cumulative,

• any liquidation preference,

• any optional redemption provisions,

• any sinking fund or other provisions that would obligate us to redeem or purchase the preferred stock,

• any terms for the conversion or exchange of the preferred stock for other securities of us or any other entity,

• any voting rights, and

• any other preferences and relative, participating, optional or other special rights or any qualifications, limitations or restrictions on the rights of the shares.

The issuance of preferred stock, while providing desired flexibility in connection with possible acquisitions and other corporate purposes, could adversely affect the voting power of holders of our common stock. It could also affect the likelihood that holders of our common stock will receive dividend payments and payments upon liquidation. The issuance of shares of preferred stock, or the issuance of rights to purchase shares of preferred stock, could be used to discourage an attempt to obtain control of us. For example, if, in the exercise of its fiduciary obligations, our board were to determine that a takeover proposal was not in our best interest, the board could authorize the issuance of a series of preferred stock containing class voting rights that would enable the holder or holders of the series to prevent or make the change of control transaction more difficult. Alternatively, a change of control transaction deemed by the board to be in our best interest could be facilitated by issuing a series of preferred stock having sufficient voting rights to provide a required percentage vote of the shareholders.

Anti-Takeover Effects of Texas Laws and Our Charter and Bylaw Provisions

Some provisions of Texas law and our Articles of Incorporation and Bylaws could make the following actions more difficult:

• acquisition of us by means of a tender offer,

• acquisition of control of us by means of a proxy contest or otherwise, or

• removal of our incumbent officers and directors.

These provisions are designed to discourage coercive takeover practices and inadequate takeover bids. These provisions are also designed to encourage persons seeking to acquire control of us to first negotiate with our board of directors. We believe that the benefits of this increased protection gives us the potential ability to negotiate with the proponent of an unfriendly or unsolicited proposal to acquire or restructure us, and that the benefits of this increased protection outweigh the disadvantages of discouraging those proposals, because negotiation of those proposals could result in an improvement of their terms.

Charter and Bylaw Provisions

Election and Removal of Directors. The number of members of our board of directors will be fixed from time to time by resolution of the board of directors. Except for voting rights as may be provided to holders of preferred stock, at each annual meeting of shareholders, all directors are elected to hold office for a term expiring at the next succeeding annual meeting of shareholders and until their successors have been elected and qualified.

No director may be removed except for cause, and, subject to the voting rights expressly conferred to the holders of our preferred stock, directors may be removed for cause only by the holders of at least a majority of the shares of capital stock entitled to vote at an election of directors. Subject to the voting rights expressly conferred to the holders of our preferred stock, any vacancy occurring on the board of directors and any newly created directorship may be filled by a majority of the remaining directors in office or by election by the shareholders.

Shareholder Meetings. Our Articles of Incorporation and Bylaws provide that special meetings of holders of common stock may be called only by the chairman of our board of directors, our chief executive officer, the president, the secretary, a majority of our board of directors or the holders of at least 50% of the shares of our capital stock outstanding and entitled to vote.

Modification of Articles of Incorporation. In general, amendments to our Articles of Incorporation that are recommended by the board of directors require the affirmative vote of holders of at least a majority of the voting power of all outstanding shares of capital stock entitled to vote in the election of directors. The provisions described above under “— Election and Removal of Directors” and “— Shareholder Meetings” may be amended only by the affirmative vote of holders of at least 66 2/3% of the voting power of all outstanding shares of capital stock entitled to vote in the election of directors. The provisions described below under “— Modification of Bylaws” may be amended only by the affirmative vote of holders of at least 80% of the voting power of all outstanding shares of capital stock entitled to vote in the election of directors.

Modification of Bylaws. Our board of directors has the power to alter, amend or repeal the Bylaws or adopt new Bylaws by the affirmative vote of at least 80% of all directors then in office at any regular or special meeting of the board of directors called for that purpose. The shareholders also have the power to alter, amend or repeal the Bylaws or adopt new Bylaws by the affirmative vote of holders of at least 80% of the voting power of all outstanding shares of capital stock entitled to vote in the election of directors, voting together as a single class.

Other Limitations on Shareholder Actions. Our Bylaws also impose some procedural requirements on shareholders who wish to:

• make nominations in the election of directors,

• propose that a director be removed,

• propose any repeal or change in the Bylaws, or

• propose any other business to be brought before an annual or special meeting of shareholders.

Under these procedural requirements, a shareholder must deliver timely notice in proper written form to our secretary of the nomination or proposal along with evidence of:

• the shareholder’s status as a shareholder,

• the number of shares beneficially owned by the shareholder,

• a list of the persons with whom the shareholder is acting in concert, and

• the number of shares such persons beneficially own.

To be timely, a shareholder must deliver the notice:

• in connection with an annual meeting of shareholders, not less than 90 days nor more than 180 days prior to the first anniversary of the date on which the immediately preceding year’s annual meeting of shareholders was held; provided that if the date of the annual meeting is advanced by more than 30 days prior to or delayed by more than 60 days after the first anniversary of the preceding year’s annual meeting of shareholders, not earlier than 180 days prior to the annual meeting and not later than the last to occur of (i) the 90th day prior to the annual meeting or (ii) the 10th day following the day on which we first make public announcement of the date of the annual meeting, or

• in connection with the nomination of director candidates at a special meeting of shareholders, generally not less than 40 days nor more than 60 days prior to the date of the special meeting.

To submit a nomination for the board of directors, a shareholder must also submit information with respect to the nominee that we would be required to include in a proxy statement, as well as some other information. If a shareholder fails to follow the required procedures, the shareholder’s nominee or proposal will be ineligible and will not be voted on by our shareholders.

In addition to the director nomination provisions described above, our Bylaws contain a “proxy access” provision that provides that any shareholder or group of up to twenty shareholders who have owned 3% or more of our outstanding common stock continuously for at least three years to nominate and include in our proxy materials for an annual meeting of shareholders, director candidates constituting up to 20% of our board of directors or two directors, whichever is greater, provided that the shareholder (or group) and each nominee satisfy the eligibility requirements specified in our Bylaws. An eligible shareholder (or group) proposing to nominate a person for election to our board of directors through the proxy access provision must provide us with a notice requesting the inclusion of the director nominee in our proxy materials and other required information not less than 120 days nor more than 150 days prior to the first anniversary of the date on which the immediately preceding year’s annual meeting of shareholders was held. In addition, an eligible shareholder (or group) may include a written statement of not more than 500 words supporting the candidacy of such shareholder nominee. The complete proxy access provision for director nominations are set forth in our Bylaws.

In connection with a special meeting of shareholders, the only business that will be conducted is that stated in the notice of special meeting, or otherwise properly brought and made in proper written form before the meeting by or at the direction of the Chairman of the Meeting or the board of directors. Shareholders requesting a special meeting are permitted to make proposals for matters to be brought before the meeting in their request.

Limitation on Liability of Directors. Our Articles of Incorporation provide that no director will be personally liable to us or our shareholders for monetary damages for breach of fiduciary duty as a director, except as required by law as in effect from time to time. Currently, Texas law requires that liability be imposed for the following actions:

• any breach of the director’s duty of loyalty to us or our shareholders,

• any act or omission not in good faith that constitutes a breach of duty of the director to the corporation or that involves intentional misconduct or a knowing violation of law,

• a transaction from which the director received an improper benefit, regardless of whether or not the benefit resulted from an action taken within the scope of a director’s duties, and

• an act or omission for which the liability of a director is expressly provided for by statute.

Our Bylaws provide that we will indemnify our officers and directors and advance expenses to them in connection with proceedings and claims, to the fullest extent permitted by the TBOC. The Bylaws authorize our board of directors to indemnify and advance expenses to people other than our officers and directors in certain circumstances.

Texas Anti-Takeover Law

We are subject to Section 21.606 of the TBOC. That section prohibits Texas public corporations from engaging in a wide range of specified transactions with any affiliated shareholder during the three-year period immediately following the affiliated shareholder’s acquisition of shares in the absence of certain board of director or shareholder approvals. An affiliated shareholder of a corporation is any person, other than the corporation and any of its wholly owned subsidiaries, that is or was within the preceding three-year period the beneficial owner of 20% or more of the outstanding shares of stock entitled to vote generally in the election of directors. Section 21.606 may deter any potential unfriendly offers or other efforts to obtain control of us that are not approved by our board of directors. This may deprive our shareholders of opportunities to sell shares of our common stock at a premium to the prevailing market price.

Listing. Our common stock is traded on the New York Stock Exchange and the Chicago Stock Exchange under the trading symbol “CNP.”

DESCRIPTION OF OUR SERIES B PREFERRED STOCK

The following description is a summary of certain terms of our 7.00% Series B Mandatory Convertible Preferred Stock, par value $0.01 per share, which we refer to in this Exhibit 4(hh) as our Series B Preferred Stock, but is not necessarily complete. It is subject to and qualified in its entirety by reference to our Articles of Incorporation, including the Statement of Resolution for our Series B Preferred Stock (the “Statement of Resolution”), and Bylaws, each of which are incorporated by reference as an exhibit to the Annual Report on Form 10-K of which this Exhibit 4(hh) is a part. We encourage you to read our Articles of Incorporation, our Bylaws, the Statement of Resolution and the applicable provisions of the TBOC for additional information.

General

Under our Articles of Incorporation, our board of directors is authorized, without further shareholder action, to issue up to 20,000,000 shares of preferred stock, par value $0.01 per share, in one or more series, with such designations, preferences, limitations and relative rights, voting, redemption and other rights and the qualifications, limitations and restrictions as shall be set forth in the resolutions providing therefor. On August 22, 2018, we issued 800,000 shares ($800 million aggregate liquidation preference) of our Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Stock (the “Series A Preferred Stock”). We currently have no other shares of preferred stock outstanding.

Our Series B Preferred Stock and any shares of our common stock issued upon the conversion of our Series B Preferred Stock will be fully paid and nonassessable. The holders of our Series B Preferred Stock will have no preemptive or preferential rights to purchase or subscribe to stock, obligations, warrants or other securities of CenterPoint Energy of any class. Broadridge Corporate Issuer Solutions, Inc. is the transfer agent, registrar and dividend disbursing agent of our common stock and will serve as transfer agent, registrar and conversion and dividend disbursing agent for our Series B Preferred Stock.

Ranking

Our Series B Preferred Stock will, with respect to dividends and distributions upon the liquidation, dissolution and winding up of our affairs, rank:

• senior to our common stock and to each other class or series of our capital stock established after the original issue date of our Series B Preferred Stock (which we refer to as the “initial issue date”) that is expressly made subordinated to our Series B Preferred Stock as to the payment of dividends or amounts payable on a liquidation, dissolution or winding up of our affairs (the “Junior Stock”);

• on a parity with our Series A Preferred Stock and any class or series of our capital stock established after the initial issue date that is not expressly made senior or subordinated to our Series B Preferred Stock as to the payment of dividends and amounts payable on a liquidation, dissolution or winding up of our affairs (the “Parity Stock”);

• junior to any class or series of our capital stock established after the initial issue date that is expressly made senior to our Series B Preferred Stock as to the payment of dividends or amounts payable on a liquidation, dissolution or winding up of our affairs (the “Senior Stock”);

• junior to all of our existing and future indebtedness (including indebtedness outstanding under our credit facilities, our senior notes and our commercial paper) and other liabilities with respect to assets available to satisfy claims against us; and

• structurally subordinated to any existing and future indebtedness and other liabilities of our subsidiaries and capital stock of our subsidiaries held by third parties.

We may issue Parity Stock and Junior Stock from time to time in one or more series without the consent of the holders of our Series B Preferred Stock. Our ability to issue any Senior Stock is limited as described under “—Voting Rights.”

Parity Stock with respect to our Series B Preferred Stock may include series of our preferred stock that have different dividend rates, redemption or conversion features, mechanics, dividend periods (e.g., semi-annual rather than quarterly), payment dates or record dates than our Series B Preferred Stock.

Dividends

Subject to the rights of holders of any class or series of capital stock ranking senior to our Series B Preferred Stock with respect to dividends, holders of shares of our Series B Preferred Stock will be entitled to receive, when, as and if declared by our board of directors, or an authorized committee thereof, out of our surplus (the amount by which our net assets exceed our stated capital) (the “funds available to pay dividends”), cumulative dividends at the rate per annum of 7.00% on the liquidation preference of $1,000 per share of our Series B Preferred Stock (equivalent to $70.00 per annum per share), payable in cash, by delivery of shares of our common stock or through any combination of cash and shares of our common stock, as determined by us in our sole discretion (subject to the limitations described below). See “—Method of Payment of Dividends.” Declared dividends on our Series B Preferred Stock will be payable quarterly on March 1, June 1, September 1 and December 1 of each year to, and including, September 1, 2021, commencing December 1, 2018 (each, a “dividend payment date”), at such annual rate, and dividends shall accumulate from the most recent date as to which dividends shall have been paid or, if no dividends have been paid, from the initial issue date of our Series B Preferred Stock, whether or not in any dividend period or periods there were funds available to pay dividends. Declared dividends will be payable on the relevant dividend payment date to holders of record as they appear on our stock register at 5:00 p.m., New York City time, on the February 15, May 15, August 15 or November 15, as the case may be, immediately preceding the relevant dividend payment date (each, a “record date”), whether or not such holders convert their shares, or such shares are automatically converted, after a record date and on or prior to the immediately succeeding dividend payment date. These record dates will apply regardless of whether a particular record date is a business day. A “business day” means each Monday, Tuesday, Wednesday, Thursday or Friday on which banking institutions in The City of New York are not authorized or obligated by law, regulation or executive order to close. If a dividend payment date is not a business day, payment will be made on the next succeeding business day, without any interest, dividends or other payment in lieu of interest accruing with respect to this delay.

A full dividend period is the period from, and including, a dividend payment date to, but excluding, the next dividend payment date, except that the initial dividend period will commence on, and include, the initial issue date of our Series B Preferred Stock and will end on, and exclude, the December 1, 2018 dividend payment date. The amount of dividends payable on each share of our Series B Preferred Stock for each full dividend period (after the initial dividend period) will be computed by dividing the annual dividend rate by four. Dividends payable on our Series B Preferred Stock for the initial dividend period and any partial dividend period will be computed based upon the actual number of days elapsed during the period over a 360-day year (consisting of twelve 30-day months). Accordingly, the dividend on our Series B Preferred Stock for the first dividend period, assuming the initial issue date is October 1, 2018, will be approximately $11.6667 per share (based on the annual dividend rate of 7.00% and a liquidation preference of $1,000 per share) and will be payable, when, as and if declared, on December 1, 2018. The dividend on our Series B Preferred Stock for each subsequent full dividend period, when, as and if declared, will be $17.50 per share (based on the annual dividend rate of 7.00% and a liquidation preference of $1,000 per share). Accumulated dividends will not bear interest if they are paid subsequent to the applicable dividend payment date.

No dividend will be declared or paid upon, or any sum of cash or number of shares of our common stock set apart for the payment of dividends upon, any outstanding share of our Series B Preferred Stock with respect to any dividend period unless all dividends for all preceding dividend periods have been declared and paid upon, or a sufficient sum of cash or number of shares of our common stock have been set apart for the payment of such dividends upon, all outstanding shares of our Series B Preferred Stock.

Our ability to declare and pay cash dividends and make other distributions with respect to our capital stock, including our Series B Preferred Stock, may be limited by the terms of any future indebtedness, including under any future revolving credit facility. In addition, our ability to declare and pay dividends may be limited by applicable Texas law.

We will not declare or pay, or set aside for payment, full dividends on our Series B Preferred Stock or any Parity Stock for any dividend period unless full cumulative dividends have been paid or provided for on our Series B Preferred Stock and any Parity Stock through the most recently completed dividend period for each such security. To the extent dividends will not be paid in full on our Series B Preferred Stock, we will take appropriate action to ensure that all dividends declared and paid upon our Series B Preferred Stock and any Parity Stock will be reduced, declared and paid on a pro rata basis on their respective liquidation preferences.

We will not declare or pay, or set aside for payment, dividends on any Junior Stock (other than a dividend payable solely in Junior Stock) unless full cumulative dividends have been or contemporaneously are being paid on all outstanding shares of our Series B Preferred Stock and any Parity Stock through the most recently completed respective dividend periods.

In addition, unless full cumulative dividends have been or contemporaneously are being paid or provided for on all outstanding shares of our Series B Preferred Stock and any Parity Stock through the most recently completed respective dividend periods, we may not repurchase, redeem or otherwise acquire, in whole or in part, any shares of our Series B Preferred Stock or Parity Stock, except for the exchange or conversion of Parity Stock pursuant to the conversion or exchange provisions thereof for or into other Parity Stock (with the same or lesser aggregate liquidation amount) or Junior Stock and the payment of cash in lieu of fractional shares. Further, we may not redeem, repurchase or otherwise acquire shares of our common stock or any other Junior Stock (other than (1) as a result of a reclassification of Junior Stock for or into other Junior Stock, (2) the exchange or conversion of one share of Junior Stock for or into another share of Junior Stock, (3) purchases, redemptions or other acquisitions of shares of Junior Stock in connection with any dividend reinvestment plan or shareholder stock purchase plan or any employment contract, benefit plan or other similar arrangement with or for the benefit of employees, officers, directors or consultants and (4) the purchase of fractional interests in shares of Junior Stock pursuant to the conversion or exchange provisions of such securities or the security being converted or exchanged) unless full cumulative dividends have been or contemporaneously are being paid or provided for on all outstanding shares of our Series B Preferred Stock and any Parity Stock through the most recently completed respective dividend periods.

Subject to the foregoing, and not otherwise, such dividends (payable in cash, securities or other property) as may be determined by our board of directors, or an authorized committee thereof, may be declared and paid on any securities, including our common stock and other Junior Stock, from time to time out of funds available to pay dividends, and holders of our Series B Preferred Stock shall not be entitled to participate in any such dividends.

Our Series B Preferred Stock will rank junior as to payment of dividends to any class or series of our Senior Stock that we may issue in the future. If at any time we have failed to pay, on the applicable payment date, accumulated dividends on any class or series of Senior Stock, we may not pay any dividends on our outstanding Series B Preferred Stock or redeem or otherwise repurchase any shares of our Series B Preferred Stock until we have paid or set aside for payment the full amount of the unpaid dividends on the Senior Stock that must, under the terms of such securities, be paid before we may pay dividends on, or redeem or repurchase, our Series B Preferred Stock.

If our board of directors (or an authorized committee thereof) does not declare a dividend (or declares less than full dividends) payable in respect of any dividend period, such dividend (or any portion of such dividend not declared) shall accumulate and an amount equal to such accumulated dividend (or such undeclared portion thereof) shall become payable out of funds legally available therefor upon our liquidation, our dissolution or a winding up of our affairs (or earlier conversion or redemption of such shares of our Series B Preferred Stock), to the extent not paid prior to such liquidation, dissolution, winding up or earlier conversion or redemption. We will not pay interest or any sum of money instead of interest on any dividend payment that may be in arrears on our Series B Preferred Stock. Holders of our Series B Preferred Stock shall not be entitled to any dividends on the Series B Preferred Stock, whether payable in cash, property or shares of our common stock, in excess of full cumulative dividends.

Except as provided herein under “—Dividends,” dividends on our Series B Preferred Stock converted to our common stock shall cease to accumulate on the mandatory conversion date or the early conversion date (including in connection with a fundamental change), as applicable.

If we are required to withhold on distributions to a holder and pay the applicable withholding taxes, we may, at our option, withhold such taxes from payments of cash or shares of our common stock payable to such holder.

Method of Payment of Dividends

Subject to the limitations described below, we may pay any declared dividend (or any portion of any declared dividend) on our Series B Preferred Stock (whether or not for a current dividend period or any prior dividend period), determined in our sole discretion:

• by paying cash;

• by delivering shares of our common stock (or, as described below, units of exchange property); or

• through any combination of paying cash and delivering shares of our common stock (or, as described below, units of exchange property).

We will make each payment of a declared dividend on our Series B Preferred Stock in cash, except to the extent we elect to make all or any portion of such payment by delivering shares of our common stock. We will give the holders of our Series B Preferred Stock notice of any such election, and the portion of such payment that will be made by paying cash and the portion that will be made by delivering our common stock, on the earlier of the date we declare such dividend and the tenth scheduled trading day (as defined below) immediately preceding the dividend payment date for such dividend.

If we elect to make any payment of a declared dividend, or any portion thereof, by delivering shares of our common stock, such shares shall be valued for such purpose at the average VWAP per share (as defined below) of our common stock over the five consecutive trading day period ending on, and including, the second trading day immediately preceding the applicable dividend payment date (the “five-day average price”), multiplied by 97%.

No fractional shares of our common stock will be delivered to the holders of our Series B Preferred Stock in respect of dividends. We will instead pay a cash adjustment (computed to the nearest cent) to each holder that would otherwise be entitled to a fraction of a share of our common stock based on the five-day average price.

To the extent a shelf registration statement is required in our reasonable judgment in connection with the issuance of or for resales of shares of our common stock issued as payment of a dividend, including dividends paid in connection with a conversion, we will, to the extent such a registration statement is not currently filed and effective, use our commercially reasonable efforts to file and maintain the effectiveness of such a shelf registration statement until the earlier of such time as all such shares of our common stock have been resold thereunder and such time as all such shares are freely tradable without registration by holders thereof that are not our affiliates and were not our affiliates in the three months immediately preceding for purposes of the Securities Act. To the extent applicable, we will also use our commercially reasonable efforts to have such shares of our common stock qualified or registered under applicable U.S. state securities laws, if required, and approved for listing on The New York Stock Exchange (or if our common stock is not listed on The New York Stock Exchange, on the principal other U.S. national or regional securities exchange on which our common stock is then listed).

Notwithstanding the foregoing, in no event will the number of shares of our common stock delivered in respect of any declared dividend exceed a number equal to the total dividend payment, divided by $9.5373, which amount represents approximately 35% of the initial price (as defined below), subject to adjustment in a manner inversely proportional to any anti-dilution adjustment to each fixed conversion rate as set forth below under “—Anti-Dilution Adjustments” (such dollar amount, as adjusted, the “floor price”). To the extent that the amount of the declared dividend as to which we have elected to deliver shares of our common stock in lieu of paying cash exceeds the product of the number of shares of our common stock delivered in connection with such declared dividend and 97% of the five-day average price, we will, if we are legally able to do so, notwithstanding any notice by us to the contrary, pay such excess amount in cash (computed to the nearest cent).

Liquidation Rights

In the event of any liquidation, dissolution or winding up of our affairs, whether voluntary or involuntary, the holders of our Series B Preferred Stock will be entitled to receive out of our assets available for distribution to shareholders, after satisfaction of liabilities to creditors, if any, and subject to the rights of holders of Senior Stock and Parity Stock in respect of distributions upon liquidation, dissolution or winding up of CenterPoint Energy, Inc., and before any distribution of assets is made to holders of Junior Stock, a liquidation preference of $1,000 per share. Any accumulated and unpaid dividends on our Series B Preferred Stock and Parity Stock will be paid prior to any distributions in liquidation, dissolution or winding up of our affairs. If, upon any liquidation, dissolution or winding up of our affairs, whether voluntary or involuntary, the amounts payable with respect to the liquidation preference or an amount equal to accumulated and unpaid dividends of our Series B Preferred Stock and all Parity Stock, as the case may be, are not paid in full, the holders of our Series B Preferred Stock and any Parity Stock will share equally and ratably in any distribution of our assets in proportion to the respective liquidation preferences or amounts equal to accumulated and unpaid dividends, as applicable, to which they are entitled.

After payment of the full amount of the liquidation preference and an amount equal to accumulated and unpaid dividends to which they are entitled, the holders of our Series B Preferred Stock will have no right or claim to any of our remaining assets.

Neither the sale of all or substantially all of our assets or business (other than in connection with our liquidation, dissolution or winding up of our affairs), nor our merger or consolidation into or with any other person, will be deemed to be our voluntary or involuntary liquidation, dissolution or winding up of our affairs.

The Statement of Resolution does not contain any provision requiring funds to be set aside to protect the liquidation preference of our Series B Preferred Stock even though it is substantially in excess of the par value thereof.

Voting Rights

Our Series B Preferred Stock will have no voting, consent or approval rights except as set forth below or as otherwise provided by Texas law.

Whenever dividends on any shares of our Series B Preferred Stock, or any other voting preferred stock (as defined below), have not been declared and paid for the equivalent of six or more dividend periods (including, for the avoidance of doubt, the dividend period beginning on, and including, the initial issue date and ending on, but excluding, December 1, 2018), whether or not for consecutive dividend periods (a “nonpayment”), the holders of such shares of our Series B Preferred Stock, voting together as a single class with holders of any and all other series of voting preferred stock then outstanding, will be entitled at our next annual or special meeting of shareholders as provided below to vote for the election of a total of two additional members of our board of directors (the “preferred stock directors”); provided that the election of any such directors will not cause us to violate the corporate governance requirements of The New York Stock Exchange (or any other exchange or automated quotation system on which our securities may be listed or quoted) that requires listed or quoted companies to have a majority of independent directors; and provided further that our board of directors shall at no time include more than two preferred stock directors. In the event of a nonpayment, we will increase the number of directors on our board of directors by two, and the new directors will be elected at a special meeting of shareholders called by our board of directors at the request of the holders of at least 20% of the shares of our Series B Preferred Stock or of any other series of voting preferred stock (provided that if such request is received less than 90 calendar days before the date fixed for the next annual or special meeting of the shareholders, such election shall be held at such next annual or special meeting of shareholders), and at each subsequent annual meeting, so long as the holders of our Series B Preferred Stock continue to have such voting rights. Any request to call a special meeting for the initial election of the preferred stock directors after a nonpayment shall be made by written notice, signed by the requisite holders of our Series B Preferred Stock or holders of any other series of voting preferred stock, and delivered to us in such manner as provided for in the Articles of Incorporation, the Statement of Resolution, or as may otherwise be required by law.

As used herein, “voting preferred stock” means any other class or series of our Parity Stock upon which like voting rights have been conferred and are exercisable. Whether a plurality, majority or other portion of our Series B Preferred Stock and any other voting preferred stock have been voted in favor of any matter shall be determined by reference to the respective liquidation preference amounts of our Series B Preferred Stock and such other voting preferred stock voted. Any shares of our Series B Preferred Stock or any other voting preferred stock, in each case, held by any of our affiliates will not be entitled to vote.

If and when all accumulated and unpaid dividends have been paid in full, or declared and a sum sufficient for such payment shall have been set aside (a “nonpayment remedy”), the holders of our Series B Preferred Stock shall immediately and, without any further action by us, be divested of the foregoing voting rights, subject to the revesting of such rights in the event of each subsequent nonpayment. If such voting rights for the holders of our Series B Preferred Stock and all other holders of voting preferred stock have terminated, the term of office of each preferred stock director so elected will terminate at such time and the number of directors on our board of directors shall automatically decrease by two.

Any preferred stock director may be removed at any time without cause by the holders of record of a majority of the outstanding shares of our Series B Preferred Stock and any other shares of voting preferred stock then outstanding (voting together as a single class) when they have the voting rights described above. In the event that a nonpayment shall have occurred and there shall not have been a nonpayment remedy, any vacancy in the office of a preferred stock director (other than prior to the initial election after a nonpayment) may be filled by the written consent of the preferred stock director remaining in office or, if none remains in office, by a vote of the holders of record of a majority of the outstanding shares of our Series B Preferred Stock and any other shares of voting preferred stock then outstanding (voting together as a single class) when they have the voting rights described above; provided that the filling of each vacancy will not cause us to violate the corporate governance requirements of The New York Stock Exchange (or any other exchange or automated quotation system on which our securities may be listed or quoted) that requires listed or quoted companies to have a majority of independent directors. The preferred stock directors will each be entitled to one vote per director on any matter that comes before our board of directors for a vote.

Unless we have received the affirmative vote or consent of the holders of at least two-thirds of the outstanding shares of our Series B Preferred Stock, voting as a single class, we may not amend our Articles of Incorporation or the Statement of Resolution in a way that would have an adverse effect on the existing powers, preferences, rights, qualifications, limitations and restrictions of our Series B Preferred Stock. For purposes of this voting requirement, any amendment to our Articles of Incorporation or to the Statement of Resolution (i) relating to the issuance or any increase in authorization of additional shares of preferred stock (subject to the voting rights regarding the issuance of Senior Stock discussed below) and (ii) in connection with a merger or another transaction in which either (x) we are the surviving entity and our Series B Preferred Stock remains outstanding or (y) our Series B Preferred Stock is exchanged for a series of preferred stock of the surviving entity, in either case, with the terms thereof unchanged in any respect materially adverse to the holders of our Series B Preferred Stock, will be deemed not to adversely affect the powers, preferences, rights, qualifications, limitations and restrictions of our Series B Preferred Stock.

In addition, unless we have received the affirmative vote or consent of the holders of at least two-thirds of the outstanding shares of our Series B Preferred Stock, voting together as a single class with holders of any and all other series of voting preferred stock then outstanding, we may not create or issue any Senior Stock.

On any matter described above in which the holders of our Series B Preferred Stock are entitled to vote separately as a class, such holders will be entitled to one vote per share. Any shares of our Series B Preferred Stock held by any of our affiliates will not be entitled to vote.

With respect to shares of our Series B Preferred Stock that are held for a person’s account by another person (such as a broker, dealer, bank, trust company or clearing corporation, or an agent of any of the foregoing), in whose name such shares are registered, such other person will, in exercising the voting rights in respect of such shares of Series B Preferred Stock on any matter, and unless the arrangement between such persons provides otherwise, vote such Series B Preferred Stock in favor of, and at the direction of, the person who is the beneficial owner, and we will be entitled to assume it is so acting without further inquiry.

Without the consent of the holders of our Series B Preferred Stock, we may amend, alter, supplement, or repeal any terms of our Series B Preferred Stock by amending, altering, supplementing or repealing our Articles of Incorporation, the Statement of Resolution or any certificate representing our Series B Preferred Stock for the following purposes:

• to cure any ambiguity, omission, inconsistency or mistake in any such agreement or instrument;

• to make any provision with respect to matters or questions relating to our Series B Preferred Stock that is not inconsistent with the provisions of the Statement of Resolution for our Series B Preferred Stock and that does not adversely affect the rights of any holder of our Series B Preferred Stock; or

• to make any other change that does not adversely affect the rights of any holder of our Series B Preferred Stock (other than any holder that consents to such change).

In addition, without the consent of the holders of our Series B Preferred Stock, we may amend, alter, supplement or repeal any terms of our Series B Preferred Stock to conform the terms of our Series B Preferred Stock to the description thereof in the related prospectus as supplemented and/or amended for our Series B Preferred Stock, as further supplemented and/or amended by the related pricing term sheet.

Mandatory Conversion

Each outstanding share of our Series B Preferred Stock, unless previously converted or redeemed, will automatically convert on the mandatory conversion date, into a number of shares of our common stock equal to the conversion rate described below. If we declare a dividend for the dividend period ending on September 1, 2021, we will pay such dividend to the holders of record as of the applicable record date, as described above under “—Dividends.” If, on or prior to August 15, 2021, we have not declared all or any portion of the accumulated and unpaid dividends on our Series B Preferred Stock, the conversion rate will be adjusted so that holders receive an additional number of shares of our common stock equal to the amount of accumulated and unpaid dividends that have not been declared (the “additional conversion amount”), divided by the greater of (i) the floor price and (ii) 97% of the five-day average price. To the extent that the additional conversion amount exceeds the product of such number of additional shares and 97% of the five-day average price, we will, if we are legally able to do so, pay such excess amount in cash (computed to the nearest cent) pro rata to the holders of our Series B Preferred Stock.

The conversion rate, which is the number of shares of our common stock issuable upon conversion of each share of our Series B Preferred Stock on the mandatory conversion date (excluding shares of our common stock issued in respect of accumulated and unpaid dividends, if any), will be as follows:

• if the applicable market value of our common stock is greater than the threshold appreciation price, then the conversion rate will be 30.5820 shares of our common stock per share of our Series B Preferred Stock (the “minimum conversion rate”), which is approximately equal to $1,000, divided by the threshold appreciation price;

• if the applicable market value of our common stock is less than or equal to the threshold appreciation price but equal to or greater than the initial price, then the conversion rate will be equal to $1,000, divided by the applicable market value of our common stock, rounded to the nearest ten-thousandth of a share, which will be between 30.5820 and 36.6980 shares of our common stock per share of our Series B Preferred Stock; or

• if the applicable market value of our common stock is less than the initial price, then the conversion rate will be 36.6980 shares of our common stock per share of our Series B Preferred Stock (the “maximum conversion rate”), which is approximately equal to $1,000, divided by the initial price.

The “initial price” equals $1,000, divided by the maximum conversion rate, rounded to the nearest $0.0001, and is approximately equal to the per share public offering price of our common stock in the Concurrent Offering.

The “threshold appreciation price” equals $1,000, divided by the minimum conversion rate, rounded to the nearest $0.0001, and represents an approximately 20.0% appreciation over the initial price.

We refer to the minimum conversion rate and the maximum conversion rate collectively as the “fixed conversion rates.” The fixed conversion rates, the initial price, the threshold appreciation price and the applicable market value are each subject to adjustment as described under “—Anti-Dilution Adjustments” below.

Hypothetical Conversion Values upon Mandatory Conversion

For illustrative purposes only, the following table shows the number of shares of our common stock that a holder of our Series B Preferred Stock would receive upon mandatory conversion of one share of our Series B Preferred Stock at various applicable market values for our common stock. The table assumes that there will be no conversion rate adjustments as described below under “—Anti-Dilution Adjustments” and that dividends on the shares of our Series B Preferred Stock will be declared and paid in cash. The actual applicable market value of shares of our common stock may differ from those set forth in the table below. Given an initial price of approximately $27.25 and a threshold appreciation price of approximately $32.70, a holder of our Series B Preferred Stock would receive on the mandatory conversion date the number of shares of our common stock per share of our Series B Preferred Stock set forth below:

Applicable Market Value of Our Common Stock	Number of Shares of Our Common Stock to Be Received Upon Conversion		Conversion Value (Applicable Market Value of Our Common StockMultiplied by the Number of Shares of Our Common Stock to Be Received Upon Conversion)
$20.00		36.6980	$	733.96
$22.00		36.6980	$	807.36
$24.00		36.6980	$	880.75
$26.00		36.6980	$	954.15
$27.25		36.6980	$	1,000.00
$28.00		35.7143	$	1,000.00
$30.00		33.3333	$	1,000.00
$32.00		31.2500	$	1,000.00
$32.70		30.5820	$	1,000.00
$34.00		30.5820	$	1,039.79
$36.00		30.5820	$	1,100.95
$38.00		30.5820	$	1,162.12
$40.00		30.5820	$	1,223.28

Accordingly, if the applicable market value of our common stock is greater than the threshold appreciation price, the aggregate market value of our common stock delivered upon conversion of each share of our Series B Preferred Stock will be greater than the $1,000 liquidation preference of the share of our Series B Preferred Stock, assuming that the market price of our common stock on the mandatory conversion date is the same as the applicable market value of our common stock. If the applicable market value for our common stock is equal to or greater than the initial price and equal to or less than the threshold appreciation price, the aggregate market value of our common stock delivered upon conversion of each share of our Series B Preferred Stock will be equal to the $1,000 liquidation preference of the share of our Series B Preferred Stock, assuming that the market price of our common stock on the mandatory conversion date is the same as the applicable market value of our common stock. If the applicable market value of our common stock is less than the initial price, the aggregate market value of our common stock delivered upon conversion of each share of our Series B Preferred Stock will be less than the $1,000 liquidation preference of the share of our Series B Preferred Stock, assuming that the market price of our common stock on the mandatory conversion date is the same as the applicable market value of our common stock.

Definitions

“Applicable market value” means the average VWAP per share of our common stock over the final averaging period.

“Final averaging period” means the 20 consecutive trading day period beginning on, and including, the 21st scheduled trading day immediately preceding September 1, 2021.

“Mandatory conversion date” means the second business day immediately following the last trading day of the final averaging period. The mandatory conversion date is expected to be September 1, 2021.

“Trading day” means a day on which (i) there is no “market disruption event” (as defined below) and (ii) trading in our common stock generally occurs on The New York Stock Exchange or, if our common stock is not then listed on The New York Stock Exchange, on the principal other U.S. national or regional securities exchange on which our common stock is then listed or, if our common stock is not then listed on a U.S. national or regional securities exchange, on the principal other market on which our common stock is then listed or admitted for trading. If our common stock is not so listed or admitted for trading, “trading day” means a “business day.”

“Market disruption event” means (i) a failure by the primary U.S. national or regional securities exchange or market on which our common stock is listed or admitted for trading to open for trading during its regular trading session or (ii) the occurrence or existence prior to 1:00 p.m., New York City time, on any scheduled trading day for our common stock for more than one half-hour period in the aggregate during regular trading hours of any suspension or limitation imposed on trading (by reason of movements in price exceeding limits permitted by the relevant stock exchange or otherwise) in our common stock or in any options contracts or futures contracts relating to our common stock.

A “scheduled trading day” is any day that is scheduled to be a trading day.

“VWAP” per share of our common stock on any trading day means the per share volume-weighted average price as displayed on Bloomberg page “CNP <Equity> AQR” (or its equivalent successor if such page is not available) in respect of the period from 9:30 a.m. to 4:00 p.m., New York City time, on such trading day; or, if such price is not available, “VWAP” means the market value per share of our common stock on such trading day as determined, using a volume-weighted average method, by a nationally recognized independent investment banking firm retained by us for this purpose. The “average VWAP” per share over a certain period means the arithmetic average of the VWAP per share for each trading day in such period.

Conversion at the Option of the Holder

Other than during a fundamental change conversion period (as defined below under “—Conversion at the Option of the Holder upon Fundamental Change; Fundamental Change Dividend Make-Whole Amount”), and unless we have redeemed our Series B Preferred Stock, holders of our Series B Preferred Stock have the right to convert their shares of our Series B Preferred Stock, in whole or in part (but in no event less than one share of our Series B Preferred Stock), at any time prior to September 1, 2021, into shares of our common stock at the minimum conversion rate, subject to adjustment as described under “—Anti-Dilution Adjustments” below.

If as of the effective date of any early conversion (the “early conversion date”), we have not declared all or any portion of the accumulated and unpaid dividends for all full dividend periods ending on the dividend payment date prior to such early conversion date, the minimum conversion rate will be adjusted so that converting holders receive an additional number of shares of our common stock equal to such amount of accumulated and unpaid dividends that have not been declared for such full dividend periods (the “early conversion additional conversion amount”), divided by the greater of (i) the floor price and (ii) the average VWAP per share of our common stock over the 20 consecutive trading day period ending on, and including, the trading day immediately preceding such early conversion date (the “early conversion average price”). To the extent that the early conversion additional conversion amount exceeds the product of such number of additional shares and the early conversion average price, we will not have any obligation to pay the shortfall in cash.

Except as described in the immediately preceding paragraph, upon any optional conversion of any shares of our Series B Preferred Stock pursuant to this “—Conversion at the Option of the Holder” section, we will make no payment or allowance for unpaid dividends on such shares of our Series B Preferred Stock, unless such early conversion date occurs after the record date for a declared dividend and on or prior to the immediately succeeding dividend payment date, in which case such dividend will be paid on such dividend payment date to the holder of record of the converted shares as of such record date, as described under “—Dividends.”

Conversion at the Option of the Holder upon Fundamental Change; Fundamental Change Dividend Make-Whole Amount

General

If a fundamental change (as defined below) occurs on or prior to September 1, 2021, holders of our Series B Preferred Stock will have the right (the “fundamental change early conversion right”) to: (i) convert their shares of our Series B Preferred Stock, in whole or in part (but in no event less than one share of our Series B Preferred Stock), into shares of our common stock (or units of exchange property as described below) at the fundamental change conversion rate described below; (ii) with respect to such converted shares of our Series B Preferred Stock, receive an amount equal to the present value, calculated using a discount rate of 4.08% per annum, of all dividend payments on such shares (excluding any accumulated and unpaid dividends for any dividend period prior to the effective date of the fundamental change, including for the partial dividend period, if any, from, and including, the dividend payment date immediately preceding the effective date to, but excluding, the effective date (collectively, the “accumulated dividend amount”)) for all the remaining full dividend periods and for the partial dividend period from, and including, the effective date to, but excluding, the next dividend payment date (the “fundamental change dividend make-whole amount”); and (iii) with respect to such converted shares of our Series B Preferred Stock, to the extent that, as of the effective date of the fundamental change, there is any accumulated dividend amount, receive payment of the accumulated dividend amount (clauses (ii) and (iii), together, the “make-whole dividend amount”), in the case of clauses (ii) and (iii), subject to our right to deliver shares of our common stock in lieu of all or part of such amounts as described under “—Make-Whole Dividend Amount” below; provided that, if the effective date or the conversion date falls after the record date for a declared dividend and prior to the next dividend payment date, such dividend will be paid on such dividend payment date to the holders as of such record date, as described under “—Dividends,” such dividend will not be included in the accumulated dividend amount, and the fundamental change dividend make-whole amount will not include the present value of the payment of such dividend.

To exercise the fundamental change early conversion right, holders must submit their shares of our Series B Preferred Stock for conversion at any time during the period (the “fundamental change conversion period”) beginning on, and including, the effective date of such fundamental change (the “effective date”) and ending at 5:00 p.m., New York City time, on the date that is 20 calendar days after such effective date (or, if later, the date that is 20 calendar days after holders receive notice of such fundamental change, but in no event later than September 1, 2021). Holders of our Series B Preferred Stock who submit their shares for conversion during the fundamental change conversion period will have such shares converted at the conversion rate specified in the table below (the “fundamental change conversion rate”) and will be entitled to receive the make-whole dividend amount. Holders of our Series B Preferred Stock who do not submit their shares for conversion during the fundamental change conversion period will not be entitled to convert their shares of our Series B Preferred Stock at the fundamental change conversion rate or to receive the make-whole dividend amount.

We will notify holders of our Series B Preferred Stock of a fundamental change no later than the second business day following the effective date of such fundamental change.

A “fundamental change” will be deemed to have occurred, at any time after the initial issue date of our Series B Preferred Stock, if any of the following occurs:

(1) a “person” or “group” within the meaning of Section 13(d) of the Exchange Act, other than us, our wholly owned subsidiaries and our or their employee benefit plans, becomes the direct or indirect “beneficial owner,” as defined in Rule 13d-3 under the Exchange Act, of our common stock representing more than 50% of the voting power of our common stock;

(2) the consummation of (A) any recapitalization, reclassification or change of our common stock (other than a change only in par value, from par value to no par value or from no par value to par value, or changes resulting from a subdivision or combination of our common stock) as a result of which our common stock would be converted into, would be exchanged for, or would represent solely the right to receive, stock, other securities, other property or assets; (B) any share exchange, consolidation or merger of us pursuant to which our common stock will be converted into, will be exchanged for, or will represent solely the right to receive, stock, other securities, other property or assets; or (C) any sale, lease or other transfer in one transaction or a series of transactions of all or substantially all of the consolidated assets of us and our subsidiaries, taken as a whole, to any person other than one or more of our wholly-owned subsidiaries; or

(3) our common stock (or other exchange property) ceases to be listed or quoted on any of The New York Stock Exchange, The Nasdaq Global Select Market or The Nasdaq Global Market (or any of their respective successors).

A transaction or transactions described in clause (1) or clause (2) above will not constitute a fundamental change, however, if at least 90% of the consideration received or to be received by all holders of our common stock (excluding cash payments for fractional shares or pursuant to dissenters’ appraisal rights) in connection with such transaction or transactions consists of shares of common stock that are listed or quoted on any of The New York Stock Exchange, The Nasdaq Global Select Market or The Nasdaq Global Market (or any of their respective successors), or will be so listed or quoted when issued or exchanged in connection with such transaction or transactions, and as a result of such transaction or transactions our Series B Preferred Stock becomes convertible into or exchangeable for such consideration (and cash in lieu of fractional shares or pursuant to dissenters’ appraisal rights).

If any transaction in which our common stock is replaced by the securities of another entity occurs, following completion of any related fundamental change conversion period (or, if none, on the effective date of such transaction), references to us in the definition of “fundamental change” above shall instead be references to such other entity.

Fundamental Change Conversion Rate

The fundamental change conversion rate will be determined by reference to the table below and is based on the effective date of the fundamental change and the price (the “stock price”) paid (or deemed paid) per share of our common stock in such transaction. If all holders of our common stock receive only cash in exchange for their common stock in a fundamental change described in clause (2)(A) or (2)(B) of such definition, the stock price shall be the cash amount paid per share of our common stock. Otherwise the stock price shall be the average VWAP per share of our common stock over the five consecutive trading day period ending on, and including, the trading day immediately preceding the effective date of the relevant fundamental change.

The stock prices set forth in the first row of the table (i.e., the column headers) will be adjusted as of any date on which the fixed conversion rates of our Series B Preferred Stock are adjusted. The adjusted stock prices will equal the stock prices applicable immediately prior to such adjustment, multiplied by a fraction, the numerator of which is the minimum conversion rate immediately prior to the adjustment giving rise to the stock price adjustment and the denominator of which is the minimum conversion rate as so adjusted. Each of the fundamental change conversion rates in the table will be subject to adjustment in the same manner and at the same time as each fixed conversion rate as set forth under “—Anti-Dilution Adjustments.”

The following table sets forth the fundamental change conversion rate per share of our Series B Preferred Stock for each stock price and effective date set forth below.

	Stock Price
Effective Date	$10.00		$20.00		$27.25		$28.00		$30.00		$32.70		$37.50		$45.00		$55.00		$70.00		$100.00
October 1, 2018		26.4720		29.8600		29.7120		29.6200		29.3320		28.9420		28.4700		28.3480		28.6000		28.9660		29.3820
September 1, 2019		29.5840		32.0480		31.3260		31.1460		30.6100		29.9040		29.1060		29.0280		29.2400		29.4900		29.7720
September 1, 2020		33.0760		34.4220		33.2700		32.9540		31.9740		30.7620		29.7960		29.7680		29.8980		30.0280		30.1700
September 1, 2021		36.6980		36.6980		36.6980		35.7140		33.3340		30.5820		30.5820		30.5820		30.5820		30.5820		30.5820

The exact stock price and effective date may not be set forth in the table, in which case:

• if the stock price is between two stock prices on the table or the effective date is between two effective dates on the table, the fundamental change conversion rate will be determined by straight-line interpolation between the fundamental change conversion rates set forth for the higher and lower stock prices and the earlier and later effective dates, as applicable, based on a 365- or 366-day year, as applicable;

• if the stock price is in excess of $100.00 per share (subject to adjustment in the same manner as the prices in the column headings of the table above), then the fundamental change conversion rate will be the minimum conversion rate, subject to adjustment; and

• if the stock price is less than $10.00 per share (subject to adjustment in the same manner as the prices in the column headings of the table above), then the fundamental change conversion rate will be the maximum conversion rate, subject to adjustment.

Our obligation to deliver shares at the fundamental change conversion rate and pay the fundamental change dividend make-whole amount could be considered a penalty, in which case the enforceability thereof would be subject to general principles of reasonableness of economic remedies.

Make-Whole Dividend Amount

For any shares of our Series B Preferred Stock that are converted during the fundamental change conversion period, subject to the limitations described below, we may pay the make-whole dividend amount, determined in our sole discretion:

• by paying cash;

• by delivering shares of our common stock; or

• through any combination of paying cash and delivering shares of our common stock.

We will pay the make-whole dividend amount in cash, except to the extent we elect on or prior to the business day following the effective date of a fundamental change to make all or any portion of such payments by delivering shares of our common stock. If we elect to make any such payment, or any portion thereof, by delivering shares of our common stock, such shares shall be valued for such purpose at the greater of (i) the floor price and (ii) 97% of the stock price.

No fractional shares of our common stock will be delivered to the holders of our Series B Preferred Stock in respect of the make-whole dividend amount. We will instead pay a cash adjustment (computed to the nearest cent) to each converting holder that would otherwise be entitled to a fraction of a share of our common stock based on the average VWAP per share of our common stock over the five consecutive trading day period ending on, and including, the trading day immediately preceding the conversion date.

Notwithstanding the foregoing, with respect to any conversion of our Series B Preferred Stock in connection with a fundamental change, in no event will the number of shares of our common stock that we deliver in lieu of paying all or any portion of the make-whole dividend amount in cash exceed a number equal to the portion of the make-whole dividend amount to be paid by the delivery of our common stock, divided by the greater of (i) the floor price and (ii) 97% of the stock price. To the extent that the portion of the make-whole dividend amount as to which we have elected to deliver shares of our common stock in lieu of paying cash exceeds the product of the number of shares of our common stock delivered in respect of such portion of the make-whole dividend amount and 97% of the stock price, we will, if we are legally able to do so, notwithstanding any notice by us to the contrary, pay such excess amount in cash (computed to the nearest cent).

In addition, if we are prohibited from paying or delivering, as the case may be, the make-whole dividend amount (whether in cash or in shares of our common stock), in whole or in part, due to limitations of applicable Texas law, the fundamental change conversion rate will instead be increased by a number of shares of our common stock equal to the cash amount of the aggregate unpaid and undelivered make-whole dividend amount, divided by the greater of (i) the floor price and (ii) 97% of the stock price for the relevant fundamental change. To the extent that the cash amount of the aggregate unpaid and undelivered make-whole dividend amount exceeds the product of such number of additional shares and 97% of the stock price for the relevant fundamental change, we will not have any obligation to pay the shortfall in cash.

Not later than the second business day following the effective date of a fundamental change, we will notify holders of:

• the fundamental change conversion rate;

• the fundamental change dividend make-whole amount and whether we will pay such amount, or any portion thereof, by delivering shares of our common stock and, if applicable, the portion of such amount that will be paid by delivering shares of our common stock; and

• the accumulated dividend amount and whether we will pay such amount, or any portion thereof, by delivering shares of our common stock and, if applicable, the portion of such amount that will be paid by delivering shares of our common stock.

Conversion Procedures

Upon Mandatory Conversion

Any outstanding shares of our Series B Preferred Stock will automatically convert into shares of our common stock on the mandatory conversion date and cease to be outstanding (subject to the right of holders of such shares to receive shares of our common stock issuable upon conversion and other amounts and shares of our common stock, if any, to which they are entitled). The person or persons entitled to receive the shares of our common stock issuable upon mandatory conversion of our Series B Preferred Stock will be treated as the record holder(s) of such shares as of 5:00 p.m., New York City time, on the mandatory conversion date. Except as provided under “—Anti-Dilution Adjustments,” prior to 5:00 p.m., New York City time, on the mandatory conversion date, the shares of our common stock issuable upon conversion of our Series B Preferred Stock will not be deemed to be outstanding for any purpose and holders of our Series B Preferred Stock will have no rights with respect to such shares of our common stock, including voting rights, rights to respond to tender offers and rights to receive any dividends or other distributions on our common stock, by virtue of holding our Series B Preferred Stock.

Upon Early Conversion

If a holder elects to convert its shares of our Series B Preferred Stock prior to September 1, 2021, in the manner described under “—Conversion at the Option of the Holder” or “—Conversion at the Option of the Holder upon Fundamental Change; Fundamental Change Dividend Make-Whole Amount,” such holder must observe the conversion procedures set forth in this “—Upon Early Conversion” section.

If such holder holds a beneficial interest in a global share of our Series B Preferred Stock, to convert its shares of our Series B Preferred Stock, such holder must deliver to DTC the appropriate instruction form for conversion pursuant to DTC’s conversion program and, if such holder’s shares of our Series B Preferred Stock are held in certificated form, such holder must comply with certain procedures set forth in the Statement of Resolution.

The conversion date will be the date on which the converting holder has satisfied the foregoing requirements. A holder that converts its shares of our Series B Preferred Stock will not be required to pay any taxes or duties relating to the issuance or delivery of our common stock if such holder exercises its conversion rights, except that such holder will be required to pay any tax or duty that may be payable relating to any transfer involved in the issuance or delivery of our common stock in a name other than the name of such holder. Shares of our common stock will be issued and delivered only after all applicable taxes and duties, if any, payable by the converting holder have been paid in full and will be issued on the later of the second business day immediately succeeding the conversion date and the business day after such holder has paid in full all applicable taxes and duties, if any.

Any shares of our Series B Preferred Stock converted early shall cease to be outstanding upon the applicable early conversion date (subject to the right of holders of such shares to receive shares of our common stock issuable upon conversion and other amounts and shares of our common stock, if any, to which they are entitled). The person or persons entitled to receive the shares of our common stock issuable upon conversion of our Series B Preferred Stock will be treated as the record holder(s) of such shares as of 5:00 p.m., New York City time, on the applicable conversion date. Prior to 5:00 p.m., New York City time, on the applicable conversion date, the shares of our common stock issuable upon conversion of our Series B Preferred Stock will not be deemed to be outstanding for any purpose and a holder of shares of our Series B Preferred Stock will have no rights with respect to such shares of our common stock (including voting rights, rights to respond to tender offers and rights to receive any dividends or other distributions on our common stock) by virtue of holding our Series B Preferred Stock.

Fractional Shares

No fractional shares of our common stock will be issued to holders of our Series B Preferred Stock upon conversion. In lieu of any fractional shares of our common stock otherwise issuable in respect of the aggregate number of shares of our Series B Preferred Stock of any holder that are converted, that holder will be entitled to receive an amount in cash (computed to the nearest cent) equal to the product of: (i) that same fraction; and (ii) the average VWAP per share of our common stock over the five consecutive trading day period ending on, and including, the trading day immediately preceding the relevant conversion date.

If more than one share of our Series B Preferred Stock is surrendered for conversion at one time by or for the same holder, the number of shares of our common stock issuable upon conversion thereof shall be computed on the basis of the aggregate number of shares of our Series B Preferred Stock so surrendered.

Anti-Dilution Adjustments

Each fixed conversion rate will be adjusted if:

(1) We issue shares of our common stock to all or substantially all holders of our common stock as a dividend or other distribution, in which event, each fixed conversion rate in effect at 5:00 p.m., New York City time, on the date fixed for determination of the holders of our common stock entitled to receive such dividend or other distribution will be multiplied by a fraction:

• the numerator of which is the sum of (i) the number of shares of our common stock outstanding at 5:00 p.m., New York City time, on the date fixed for such determination and (ii) the total number of shares of our common stock constituting such dividend or other distribution, and

• the denominator of which is the number of shares of our common stock outstanding at 5:00 p.m., New York City time, on the date fixed for such determination.

Any increase made pursuant to this clause (1) will become effective immediately after 5:00 p.m., New York City time, on the date fixed for such determination. If any dividend or distribution described in this clause (1) is declared but not so paid or made, each fixed conversion rate shall be decreased, effective as of the date our board of directors, or an authorized committee thereof, publicly announces its decision not to make such dividend or distribution, to such fixed conversion rate that would be in effect if such dividend or distribution had not been declared. For the purposes of this clause (1), the number of shares of our common stock outstanding at 5:00 p.m., New York City time, on the date fixed for such determination shall not include shares held in treasury but shall include any shares issuable in respect of any scrip certificates issued in lieu of fractions of shares of our common stock. We will not pay any dividend or make any distribution on shares of our common stock held in treasury.

(2) We issue to all or substantially all holders of our common stock rights, options or warrants entitling them, for a period of up to 45 calendar days from the date of issuance of such rights, options or warrants, to subscribe for or purchase shares of our common stock at less than the “current market price” (as defined below) of our common stock, in which case each fixed conversion rate in effect at 5:00 p.m., New York City time, on the date fixed for determination of the holders of our common stock entitled to receive such rights, options or warrants will be increased by multiplying such fixed conversion rate by a fraction:

• the numerator of which is the sum of (i) the number of shares of our common stock outstanding at 5:00 p.m., New York City time, on the date fixed for such determination and (ii) the number of shares of our common stock issuable pursuant to such rights, options or warrants, and

• the denominator of which shall be the sum of (i) the number of shares of our common stock outstanding at 5:00 p.m., New York City time, on the date fixed for such determination and (ii) the number of shares of our common stock equal to the quotient of the aggregate offering price payable to exercise such rights, options or warrants, divided by the current market price of our common stock.

Any increase made pursuant to this clause (2) will become effective immediately after 5:00 p.m., New York City time, on the date fixed for such determination. In the event that such rights, options or warrants described in this clause (2) are not so issued, each fixed conversion rate shall be decreased, effective as of the date our board of directors, or an authorized committee thereof, publicly announces its decision not to issue such rights, options or warrants, to such fixed conversion rate that would then be in effect if such issuance had not been declared. To the extent that such rights, options or warrants are not exercised prior to their expiration or shares of our common stock are otherwise not delivered pursuant to such rights, options or warrants upon the exercise of such rights, options or warrants, each fixed conversion rate shall be decreased to such fixed conversion rate that would then be in effect had the increase made upon the issuance of such rights, options or warrants been made on the basis of the delivery of only the number of shares of our common stock actually delivered. In determining whether any rights, options or warrants entitle the holders thereof to subscribe for or purchase shares of our common stock at less than the current market price, and in determining the aggregate offering price payable for such shares of our common stock, there shall be taken into account any consideration received for such rights, options or warrants and the amount payable upon exercise or conversion thereof, the value of such consideration (if other than cash) to be determined in good faith by our board of directors, or an authorized committee thereof. For the purposes of this clause (2), the number of shares of our common stock at the time outstanding shall not include shares held in treasury but shall include any shares issuable in respect of any scrip certificates issued in lieu of fractions of shares of our common stock. We will not issue any such rights, options or warrants in respect of shares of our common stock held in treasury.

(3) We subdivide or combine our common stock, in which event each fixed conversion rate in effect at 9:00 a.m., New York City time, on the effective date of such subdivision or combination will be multiplied by a fraction:

• the numerator of which is the number of shares of our common stock that would be outstanding immediately after, and solely as a result of, such subdivision or combination, and

• the denominator of which is the number of shares of our common stock outstanding immediately prior to such subdivision or combination.

Any adjustment made pursuant to this clause (3) shall become effective immediately after 9:00 a.m., New York City time, on the effective date of such subdivision or combination.

(4) We distribute to all or substantially all holders of our common stock evidences of our indebtedness, shares of capital stock, securities, rights, options or warrants to acquire our capital stock, cash or other assets, excluding:

• any dividend or distribution as to which an adjustment was effected under clause (1) above (or will be so effected in accordance with the one-percent provision);

• any issuance of rights, options or warrants described in clause (2) above;

• any dividend or distribution of solely cash to all or substantially all holders of our common stock as to which the provisions set forth in clause (5) below shall apply; and

• any spin-off as to which the provisions set forth below in this clause (4) shall apply,

in which event each fixed conversion rate in effect at 5:00 p.m., New York City time, on the date fixed for the determination of holders of our common stock entitled to receive such distribution will be multiplied by a fraction:

• the numerator of which is the current market price of our common stock, and

• the denominator of which is the current market price of our common stock minus the fair market value, as determined in good faith by our board of directors, or an authorized committee thereof, on such date fixed for determination, of the portion of the evidences of indebtedness, shares of capital stock, securities, rights, options or warrants to acquire our capital stock, cash or other assets so distributed applicable to one share of our common stock.

Any increase made pursuant to the preceding paragraph will become effective immediately after 5:00 p.m., New York City time, on the date fixed for such determination. In the event that such distribution described in the preceding paragraph is not so made, each fixed conversion rate shall be decreased, effective as of the date our board of directors, or an authorized committee thereof, publicly announces its decision not to make such distribution, to such fixed conversion rate that would then be in effect if such distribution had not been declared.

In the event that we make a distribution to all or substantially all holders of our common stock consisting of capital stock of, or similar equity interests in, or relating to a subsidiary or other business unit of ours, that are, or, when issued, will be, listed or admitted for trading on a U.S. national securities exchange (herein referred to as a “spin-off”), each fixed conversion rate in effect at 5:00 p.m., New York City time, on the date fixed for the determination of holders of our common stock entitled to receive such distribution will be multiplied by a fraction:

• the numerator of which is the sum of (i) the current market price of our common stock and (ii) the current market price of the number of shares of capital stock or similar equity interests so distributed applicable to one share of our common stock as of the tenth trading day after the ex-date for such distribution, and

• the denominator of which is the current market price of our common stock.

Any increase made pursuant to the preceding paragraph shall be made immediately following the determination of the current market price of our common stock, but shall become retroactively effective immediately after 5:00 p.m., New York City time, on the date fixed for the determination of the holders of our common stock entitled to receive such distribution. In the event that such distribution described in the preceding paragraph is not so made, each fixed conversion rate shall be decreased, effective as of the date our board of directors, or an authorized committee thereof, publicly announces its decision not to make such distribution, to such fixed conversion rate that would then be in effect if such distribution had not been declared. If an adjustment to each fixed conversion rate is required under the preceding paragraph during the final averaging period, delivery of the shares of our common stock issuable upon conversion will be delayed to the extent necessary in order to complete the calculations provided for in the preceding paragraph. If a conversion date in respect of any early conversion prior to September 1, 2021 (including in connection with a fundamental change) occurs during the ten consecutive trading day period over which the current market price is determined for purposes of the preceding paragraph, then such period shall instead be deemed to be such lesser number of trading days as have elapsed between the ex-date for such spin-off and such conversion date.

(5) We make a dividend or distribution consisting exclusively of cash to all or substantially all holders of our common stock, excluding:

• any regular, quarterly cash dividend that does not exceed $0.2775 per share (the “initial dividend threshold”),

• any cash that is distributed in exchange for, or upon conversion of, our common stock in a reorganization event (as described below),

• any dividend or distribution in connection with our liquidation, winding-up or dissolution, and

• any consideration payable as part of a tender or exchange offer described in clause (6) below,

in which event, each fixed conversion rate in effect at 5:00 p.m., New York City time, on the date fixed for determination of the holders of our common stock entitled to receive such dividend or distribution will be multiplied by a fraction:

• the numerator of which is the current market price of our common stock minus the initial dividend threshold (provided that if the dividend or distribution is not a regular, quarterly cash dividend, the initial dividend threshold will be deemed to be zero), and

• the denominator of which is the current market price of our common stock minus the amount per share of our common stock of such dividend or distribution.

The initial dividend threshold is subject to adjustment on an inversely proportional basis whenever the fixed conversion rates are adjusted (except in connection with a discretionary adjustment), but no adjustment will be made to the initial dividend threshold for any adjustment made to the fixed conversion rates pursuant to this clause (5).

Any increase made pursuant to this clause (5) shall become effective immediately after 5:00 p.m., New York City time, on the date fixed for the determination of the holders of our common stock entitled to receive such dividend or distribution. In the event that any dividend or distribution described in this clause (5) is not so made, each fixed conversion rate shall be decreased, effective as of the date our board of directors, or an authorized committee thereof, publicly announces its decision not to make such dividend or distribution, to such fixed conversion rate which would then be in effect if such dividend or distribution had not been declared.

(6) We or any of our subsidiaries successfully complete a tender or exchange offer pursuant to a Schedule TO or registration statement on Form S-4 for our common stock (but, for the avoidance of doubt, excluding any securities convertible or exchangeable for our common stock), where the cash and the value of any other consideration included in the payment per share of our common stock exceeds the current market price of our common stock, in which event each fixed conversion rate in effect at 5:00 p.m., New York City time, on the date of expiration of the tender or exchange offer (the “expiration date”) will be multiplied by a fraction:

• the numerator of which shall be equal to the sum of:

(i) the aggregate cash and fair market value (as determined in good faith by our board of directors, or an authorized committee thereof) on the expiration date of any other consideration paid or payable for shares purchased in such tender or exchange offer; and

(ii) the product of:

1. the current market price of our common stock; and

2. the number of shares of our common stock outstanding immediately after such tender or exchange offer expires (after giving effect to the purchase or exchange of shares pursuant to such tender or exchange offer), and

• the denominator of which shall be equal to the product of:

(i) the current market price of our common stock; and

(ii) the number of shares of our common stock outstanding immediately prior to the time such tender or exchange offer expires (without giving effect to the purchase or exchange of shares pursuant to such tender or exchange offer).

Any increase made pursuant to this clause (6) shall be made immediately following the determination of the current market price of our common stock, but shall become retroactively effective immediately after 9:00 a.m., New York City time, on the trading day immediately following the expiration date. In the event that we are, or one of our subsidiaries is, obligated to purchase shares of our common stock pursuant to any such tender offer or exchange offer, but we are, or such subsidiary is, permanently prevented by applicable law from effecting any such purchases, or all such purchases are rescinded, then each fixed conversion rate shall be decreased to be such fixed conversion rate that would then be in effect if such tender offer or exchange offer had not been made. Except as set forth in the preceding sentence, if the application of this clause (6) to any tender offer or exchange offer would result in a decrease in each fixed conversion rate, no adjustment shall be made for such tender offer or exchange offer under this clause (6). If an adjustment to each fixed conversion rate is required pursuant to this clause (6) during the final averaging period, delivery of the related conversion consideration will be delayed to the extent necessary in order to complete the calculations provided for in this clause (6). If a conversion date in respect of any early conversion prior to September 1, 2021 (including in connection with a fundamental change) occurs during the five consecutive trading day period over which the current market price is determined for purposes of this clause (6), then such period shall instead be deemed to be such lesser number of trading days as have elapsed between the trading day immediately following the expiration date and such conversion date.

In cases where (i) the fair market value of the evidences of our indebtedness, shares of capital stock, securities, rights to acquire our capital stock, cash or other assets distributed per share of our common stock as to which clause (4) above applies (except with respect to a spin-off), or (ii) the amount of cash distributed per share of our common stock as to which clause (5) above applies, in each case, equals or exceeds the average VWAP per share of our common stock over the five consecutive trading day period ending on, and including, the trading day immediately preceding the ex-date for such distribution, rather than being entitled to an adjustment in each fixed conversion rate, holders of our Series B Preferred Stock will be entitled to receive, without converting their Series B Preferred Stock, at the same time and upon the same terms as holders of our common stock, the kind and amount of the evidences of our indebtedness, shares of capital stock, securities, rights to acquire our capital stock, cash or other assets, as the case may be, comprising the distribution that such holder would have received if such holder had owned, immediately prior to the record date for determining the holders of our common stock entitled to receive the distribution, for each share of our Series B Preferred Stock, a number of shares of our common stock equal to the maximum conversion rate in effect on the record date for such distribution.

To the extent that we have a rights plan in effect with respect to our common stock on any conversion date, upon conversion of any shares of our Series B Preferred Stock, a converting holder will receive, in addition to our common stock, the rights under the rights plan, unless, prior to such conversion date, the rights have separated from our common stock, in which case each fixed conversion rate will be adjusted at the time of separation as if we made a distribution to all holders of our common stock as described in clause (4) above (except with respect to a spin-off), subject to readjustment in the event of the expiration, termination or redemption of such rights. Any distribution of rights, options or warrants pursuant to a rights plan that would allow a holder to receive upon conversion, in addition to any shares of our common stock, the rights described therein (unless such rights, options or warrants have separated from our common stock (in which case each fixed conversion rate will be adjusted at the time of separation as if we made a distribution to all holders of our common stock as described in clause (4) above (except with respect to a spin-off), subject to readjustment in the event of the expiration, termination or redemption of such rights)) shall not constitute a distribution of rights, options or warrants that would entitle such holder to an adjustment to the fixed conversion rates.

For the purposes of determining the adjustment to the fixed conversion rates for the purposes of:

• clause (2), clause (4) in the event of an adjustment not relating to a spin-off and clause (5) above, the “current market price” of our common stock is the average VWAP per share of our common stock over the five consecutive trading day period ending on, and including, the trading day immediately preceding the ex-date with respect to the issuance or distribution requiring such computation;

• clause (4) above in the event of an adjustment relating to a spin-off, the “current market price” of our common stock, capital stock or similar equity interest, as applicable, is the average VWAP per share over the first ten consecutive trading days commencing on, and including, the trading day immediately following the ex-date of such distribution; and

• clause (6) above, the “current market price” of our common stock is the average VWAP per share of our common stock over the five consecutive trading day period commencing on, and including, the trading day immediately following the expiration date of the tender or exchange offer.

The term “ex-date,” when used with respect to any issuance or distribution, means the first date on which the shares of our common stock trade on the applicable exchange or in the applicable market, regular way, without the right to receive the issuance, dividend or distribution in question from us or, if applicable, from the seller of our common stock on such exchange or market (in the form of due bills or otherwise) as determined by such exchange or market.

In addition, we may make such increases in each fixed conversion rate as we deem advisable if our board of directors, or an authorized committee thereof, determines that such increase would be in our best interest or in order to avoid or diminish any income tax to holders of our common stock resulting from any dividend or distribution of shares of our common stock (or issuance of rights, options or warrants to acquire shares of our common stock) or from any event treated as such for income tax purposes or for any other reason. We may only make such a discretionary adjustment if we make the same proportionate adjustment to each fixed conversion rate.

In the event of a taxable distribution to holders of our common stock that results in an adjustment of each fixed conversion rate or an increase in each fixed conversion rate in our discretion, beneficial owners of our depositary shares may, in certain circumstances, be deemed to have received a distribution subject to U.S. federal income tax as a dividend, which for non-U.S. holders may be subject to U.S. federal withholding tax requirements.

If we are required to withhold on constructive distributions to a holder and pay the applicable withholding taxes, we may, at our option, withhold such taxes from payments of cash or shares of our common stock payable to such holder.

Adjustments to the fixed conversion rates will be calculated to the nearest 1/10,000th of a share. Prior to the first trading day of the final averaging period, no adjustment to a fixed conversion rate will be required unless the adjustment would require an increase or decrease of at least one percent in such fixed conversion rate. If any adjustment is not required to be made because it would not change the fixed conversion rates by at least one percent, then the adjustment will be carried forward and taken into account in any subsequent adjustment; provided, however, that with respect to adjustments to be made to the fixed conversion rates in connection with cash dividends paid by us, we will make such adjustments, regardless of whether such aggregate adjustments amount to one percent or more of the fixed conversion rates no later than September 1 of each calendar year; providedfurther that on (w) the earlier of an early conversion date (including in connection with a fundamental change) and the effective date of a fundamental change, (x) each trading day of the final averaging period, (y) the date, if any, on which we provide notice of an acquisition termination redemption and (z) any acquisition termination redemption date, adjustments to the fixed conversion rates will be made with respect to any such adjustment carried forward that has not been taken into account before such date. We refer to the immediately preceding sentence herein as the “one-percent provision.”

No adjustments to the fixed conversion rates will be made if holders of our Series B Preferred Stock may participate (other than in the case of (x) a share subdivision or share combination or (y) a tender or exchange offer), at the same time, upon the same terms and otherwise on the same basis as holders of our common stock and solely as a result of holding our Series B Preferred Stock, in the transaction that would otherwise give rise to such adjustment as if they held, for each share of our Series B Preferred Stock, a number of shares of our common stock equal to the maximum conversion rate then in effect.

The fixed conversion rates will not be adjusted except as provided above. Without limiting the foregoing, the fixed conversion rates will not be adjusted:

(a) upon the issuance of any shares of our common stock pursuant to any present or future plan providing for the reinvestment of dividends or interest payable on our securities and the investment of additional optional amounts in our common stock under any plan;

(b) upon the issuance of any shares of our common stock or rights, options or warrants to purchase those shares pursuant to any present or future employee, director or consultant benefit plan or program of or assumed by us or any of our subsidiaries;

(c) upon the issuance of any shares of our common stock pursuant to any option, warrant, right or exercisable, exchangeable or convertible security outstanding as of the date our Series B Preferred Stock were first issued (other than a rights plan as described above);

(d) for a change solely in the par value of our common stock;

(e) for sales of our common stock for cash, other than in a transaction described in clause (2) or clause (4) above;

(f) for stock repurchases that are not tender or exchange offers, including pursuant to structured or derivative transactions;

(g) as a result of a third-party tender or exchange offer, other than a tender or exchange offer by one of our subsidiaries as described in clause (6) above;

(h) for accumulated and unpaid dividends on our Series B Preferred Stock, except as described above under “—Acquisition Termination Redemption,” “—Mandatory Conversion,” “—Conversion at the Option of the Holder” and “—Conversion at the Option of the Holder upon Fundamental Change; Fundamental Change Dividend Make-Whole Amount;” or

(i) upon the payment of any regular, quarterly cash dividend to all or substantially all holders of our common stock to the extent that the per share amount of such cash dividend does not exceed the initial dividend threshold.

We will, as soon as practicable after the fixed conversion rates are adjusted, provide or cause to be provided written notice of the adjustment to the holders of shares of our Series B Preferred Stock. We will also deliver, promptly upon written request by a beneficial owner of our depositary shares, a statement setting forth in reasonable detail the method by which the adjustment to each fixed conversion rate was determined and setting forth each revised fixed conversion rate.

If an adjustment is made to the fixed conversion rates, (x) an inversely proportional adjustment also will be made to the threshold appreciation price and the initial price solely for the purposes of determining which clause of the definition of the conversion rate will apply on the mandatory conversion date and (y) an inversely proportional adjustment also will be made to the floor price. Whenever any provision of the Statement of Resolution establishing the terms of our Series B Preferred Stock requires us to calculate the VWAP per share of our common stock over a span of multiple days, our board of directors, or any authorized committee thereof, will make appropriate adjustments (including, without limitation, to the applicable market value, the early conversion average price, the stock price and the five-day average price, as the case may be) to account for any adjustments to the initial price, the threshold appreciation price, the fixed conversion rates and the floor price, as the case may be, that become effective, or any event that would require such an adjustment if the ex-date, effective date or expiration date, as the case may be, of such event occurs during the relevant period used to calculate such prices or values, as the case may be.

If:

• the record date for a dividend or distribution on our common stock occurs after the end of the final averaging period and before the mandatory conversion date, and

• that dividend or distribution would have resulted in an adjustment of the number of shares of our common stock issuable to the holders of our Series B Preferred Stock had such record date occurred on or before the last trading day of the final averaging period,

then we will deem the holders of our Series B Preferred Stock to be holders of record, for each share of our Series B Preferred Stock that they hold, of a number of shares of our common stock equal to the conversion rate for purposes of that dividend or distribution. In this case, the holders of our Series B Preferred Stock would receive the dividend or distribution on our common stock together with the number of shares of our common stock issuable upon mandatory conversion of our Series B Preferred Stock.

Recapitalizations, Reclassifications and Changes in Our Common Stock

In the event of:

• any consolidation or merger of us with or into another person (other than a merger or consolidation in which we are the continuing corporation and in which the shares of our common stock outstanding immediately prior to the merger or consolidation are not exchanged for cash, securities or other property of us or another person);

• any sale, transfer, lease or conveyance to another person of all or substantially all of our and our subsidiaries’ consolidated property and assets;

• any reclassification of our common stock into securities, including securities other than our common stock; or

• any statutory exchange of our securities with another person (other than in connection with a merger or consolidation),

in each case, as a result of which our common stock would be converted into, or exchanged for, securities, cash or other property (each, a “reorganization event”), each share of our Series B Preferred Stock outstanding immediately prior to such reorganization event shall, without the consent of the holders of our Series B Preferred Stock, become convertible into (or redeemable for, in the case of an acquisition termination redemption) the kind of securities, cash and other property that such holder would have been entitled to receive if such holder had converted its Series B Preferred Stock into shares of our common stock immediately prior to such reorganization event (such securities, cash and other property, the “exchange property,” with each “unit of exchange property” meaning the kind and amount of exchange property that a holder of one share of our common stock is entitled to receive). For purposes of the foregoing, the type and amount of exchange property in the case of any reorganization event that causes our common stock to be converted into the right to receive more than a single type of consideration (determined based in part upon any form of shareholder election) will be deemed to be the weighted average of the types and amounts of consideration actually received by the holders of our common stock in such reorganization event. We will notify holders of our Series B Preferred Stock of such weighted average as soon as practicable after such determination is made. The number of units of exchange property for each share of our Series B Preferred Stock converted or redeemed following the effective date of such reorganization event will be determined as if references to our common stock in the description of the conversion rate applicable upon mandatory conversion, acquisition termination redemption, conversion at the option of the holder and conversion at the option of the holder upon a fundamental change were to units of exchange property (without interest thereon and without any right to dividends or distributions thereon which have a record date prior to the date such shares of our Series B Preferred Stock are actually converted or redeemed). For the purpose of determining which bullet of the definition of conversion rate will apply upon mandatory conversion, and for the purpose of calculating the conversion rate if the second bullet of such definition is applicable, the value of a unit of exchange property will be determined in good faith by our board of directors, or an authorized committee thereof (which determination will be final absent manifest error), except that if a unit of exchange property includes common stock or American Depositary Receipts, or “ADRs”, that are traded on a U.S. national securities exchange, the value of such common stock or ADRs will be the average over the final averaging period of the volume-weighted average prices for such common stock or ADRs, as displayed on the applicable Bloomberg screen (as determined in good faith by our board of directors, or an authorized committee thereof (which determination will be final absent manifest error)); or, if such price is not available, the average market value per share of such common stock or ADRs over such period as determined, using a volume-weighted average method, by a nationally recognized independent investment banking firm retained by us for this purpose.

We (or any successor to us) will, as soon as reasonably practicable (but in any event within 20 calendar days) after the occurrence of any reorganization event, provide written notice to the holders of our Series B Preferred Stock of such occurrence and of the kind and amount of cash, securities or other property that constitute a unit of exchange property. Failure to deliver such notice will not affect the operation of the provisions described in this section.

In connection with any adjustment to the fixed conversion rates described above, we will also adjust the initial dividend threshold (as defined under “—Conversion Rate Adjustments”) based on the number of shares of our common stock comprising the exchange property and (if applicable) the value of any non-stock consideration comprising the exchange property as set forth in the Statement of Resolution. If the exchange property is composed solely of non-stock consideration, the initial dividend threshold will be zero.

The above provisions of this section will similarly apply to successive reorganization events and the “—Conversion Rate Adjustments” section will apply to any of our share capital (or any successor’s) received by the holders of our common stock in any such reorganization event.

Reservation of Shares

We will at all times reserve and keep available out of our authorized and unissued common stock or shares of our common stock held in treasury by us, solely for issuance upon conversion of our Series B Preferred Stock, free from any preemptive or other similar rights, the maximum number of shares of our common stock as shall be issuable from time to time upon the conversion of all the shares of our Series B Preferred Stock then outstanding (including, for the avoidance of doubt, the maximum number of shares of our common stock issuable in respect of any accumulated and unpaid dividends, equal to the maximum additional conversion amount hereunder divided by the floor price).

Transfer Agent, Registrar and Conversion and Dividend Disbursing Agent

Broadridge Corporate Issuer Solutions, Inc. is the transfer agent, registrar and conversion and dividend disbursing agent for our Series B Preferred Stock.

DESCRIPTION OF OUR DEPOSITARY SHARES

General

Each depositary share represents a 1/20th interest in a share of our Series B Preferred Stock and will initially be evidenced by a global security, as defined in and described under “—Book-Entry, Settlement and Clearance” in this section. Subject to the terms of the deposit agreement, our depositary shares will be entitled to all designations, preferences, limitations and relative rights, voting, redemption and other rights and the qualifications, limitations and restrictions of our Series B Preferred Stock, as applicable, in proportion to the fraction of a share of our Series B Preferred Stock those depositary shares represent.

In this section, references to “holders” of our depositary shares mean those who have our depositary shares registered in their own names on the books maintained by the depositary and not indirect holders who will own beneficial interests in our depositary shares registered in the street name of, or issued in book-entry form through, DTC prior to the mandatory conversion of our Series B Preferred Stock.

Conversion

Because each depositary share represents a 1/20th interest in a share of our Series B Preferred Stock, a holder of our depositary shares may elect to convert our depositary shares only in lots of 20 depositary shares, either on an early conversion date at the minimum conversion rate of 1.5291 shares of our common stock per depositary share, subject to adjustment, or during a fundamental change conversion period at the fundamental change conversion rate, as described below.

The following table sets forth the fundamental change conversion rate per depositary share, subject to adjustment as described under “Description of Our Series B Preferred Stock—Conversion at the Option of the Holder upon Fundamental Change; Fundamental Change Dividend Make-Whole Amount,” based on the effective date of the fundamental change and the stock price in the fundamental change:

	Stock Price
Effective Date	$10.00		$20.00		$27.25		$28.00		$30.00		$32.70		$37.50		$45.00		$55.00		$70.00		$100.00
October 1, 2018		1.3236		1.4930		1.4856		1.4810		1.4666		1.4471		1.4235		1.4174		1.4300		1.4483		1.4691
September 1, 2019		1.4792		1.6024		1.5663		1.5573		1.5305		1.4952		1.4553		1.4514		1.4620		1.4745		1.4886
September 1, 2020		1.6538		1.7211		1.6635		1.6477		1.5987		1.5381		1.4898		1.4884		1.4949		1.5014		1.5085
September 1, 2021		1.8349		1.8349		1.8349		1.7857		1.6667		1.5291		1.5291		1.5291		1.5291		1.5291		1.5291

The exact stock price and effective date may not be set forth in the table, in which case:

• if the stock price is between two stock prices on the table or the effective date is between two effective dates on the table, the fundamental change conversion rate per depositary share will be determined by straight-line interpolation between the fundamental change conversion rates per depositary share set forth for the higher and lower stock prices and the earlier and later effective dates, as applicable, based on a 365- or 366-day year, as applicable;

• if the stock price is in excess of $100.00 per share (subject to adjustment in the same manner as the prices in the column headings of the table above), then the fundamental change conversion rate per depositary share will be the minimum conversion rate, divided by 20, subject to adjustment; and

• if the stock price is less than $10.00 per share (subject to adjustment in the same manner as the prices in the column headings of the table above), then the fundamental change conversion rate per depositary share will be the maximum conversion rate, divided by 20, subject to adjustment.

Our obligation to deliver shares of our common stock at the fundamental change conversion rate and pay the fundamental change dividend make-whole amount (as described under “Description of Our Series B Preferred Stock—Conversion at the Option of the Holder upon Fundamental Change; Fundamental Change Dividend Make-Whole Amount”) could be considered a penalty, in which case the enforceability thereof would be subject to general principles of reasonableness of economic remedies.

On any conversion date for our Series B Preferred Stock, each depositary share corresponding to the shares of our Series B Preferred Stock so converted will be entitled to receive 1/20th of the number of shares of our common stock and the amount of any cash received by the depositary upon conversion of each share of our Series B Preferred Stock.

The following table illustrates the conversion rate per depositary share, subject to adjustment as described under “Description of Our Series B Preferred Stock—Anti-Dilution Adjustments,” based on the applicable market value of our common stock:

Applicable market value of our common stock	Conversion rate per depositary share
Greater than the threshold appreciation price	1.5291 shares of our common stock
Equal to or less than the threshold appreciation price but greater than or equal to the initial price	Between 1.5291 and 1.8349 shares of our common stock, determined by dividing $50 by the applicable market value
Less than the initial price	1.8349 shares of our common stock

After delivery of our common stock by the transfer agent to the depositary following conversion of our Series B Preferred Stock, the depositary will transfer the proportional number of shares of our common stock to the holders of our depositary shares by book-entry transfer through DTC or, if the holders’ interests are in certificated depositary receipts, by delivery of our common stock certificates for such number of shares of our common stock.

If we are required to withhold on distributions of our common stock in respect of dividends in arrears or in respect of the net present value of future dividends to a holder and pay the applicable withholding taxes, we may, at our option, withhold such taxes from payments of cash or shares of our common stock payable to such holder.

Fractional Shares

No fractional shares of our common stock will be issued to holders of our depositary shares upon conversion. In lieu of any fractional shares of our common stock otherwise issuable in respect of the aggregate number of our depositary shares of any holder that are converted, that holder will be entitled to receive an amount in cash (computed to the nearest cent) equal to the product of: (i) that same fraction; and (ii) the average VWAP per share of our common stock over the five consecutive trading day period ending on, and including, the trading day immediately preceding the conversion date.

If more than one depositary share is surrendered for, or subject to, conversion at one time by or for the same holder, the number of shares of our common stock issuable upon conversion thereof shall be computed on the basis of the aggregate number of our depositary shares so surrendered for, or subject to, conversion.

Dividends and Other Distributions

Each dividend paid on a depositary share will be in an amount equal to 1/20th of the dividend paid on the related share of our Series B Preferred Stock. So long as our depositary shares are held of record by the nominee of DTC, declared cash dividends in respect of our depositary shares will be paid to DTC in same-day funds on each dividend payment date. DTC will credit accounts of its participants in accordance with DTC’s normal procedures. The participants will be responsible for holding or disbursing such payments to beneficial owners of our depositary shares in accordance with the instructions of such beneficial owners.

The depositary will deliver any cash or shares of our common stock it receives in respect of dividends on our Series B Preferred Stock to the holders of our depositary shares in such amounts as are, as nearly as practicable, in proportion to the number of our outstanding depositary shares held by such holders, on the date of receipt or as soon as practicable thereafter.

The dividend payable on the first dividend payment date, if declared, is expected to be approximately $0.5833 per depositary share and the dividend payable on each subsequent dividend payment date, if declared, is expected to be $0.8750 per depositary share.

Record dates for the payment of dividends and other matters relating to our depositary shares will be the same as the corresponding record dates for our Series B Preferred Stock.

No fractional shares of our common stock will be delivered to the holders of our depositary shares in respect of dividends. Each holder that would otherwise be entitled to a fraction of a share of our common stock will instead be entitled to receive a cash adjustment (computed to the nearest cent) based on the average VWAP per share (as defined below) of our common stock over the five consecutive trading day period ending on, and including, the trading day immediately preceding the applicable dividend payment date.

The amount paid as dividends or otherwise distributable by the depositary with respect to our depositary shares or our underlying Series B Preferred Stock will be reduced by any amounts required to be withheld by us or the depositary on account of taxes or other governmental charges.

Redemption

If we redeem the shares of our Series B Preferred Stock represented by our depositary shares, as described under “Description of Our Series B Preferred Stock—Acquisition Termination Redemption,” the depositary will redeem our depositary shares on the acquisition termination redemption date from the cash and/or shares of our common stock, as applicable, received by the depositary as a result of the redemption of such shares of our Series B Preferred Stock held by the depositary. Because each depositary share represents a 1/20th interest in a share of our Series B Preferred Stock, the redemption price per depositary share (the “depositary share redemption price”) will be equal to 1/20th of the acquisition termination redemption amount payable with respect to one share of our Series B Preferred Stock.

If any portion of the acquisition termination redemption amount is paid by delivering shares of our common stock, then after delivery of shares of our common stock by the transfer agent to the depositary as a result of the redemption of our Series B Preferred Stock, the depositary will transfer the proportional number of shares of our common stock to the holders of our depositary shares by book-entry transfer through DTC or, if the holders’ interests are in certificated depositary receipts, by delivery of our common stock certificates for such number of shares of our common stock. No fractional shares of our common stock will be delivered to holders of our depositary shares. In lieu of any fractional shares of our common stock otherwise deliverable in respect of the aggregate number of our depositary shares of any holder that are redeemed, that holder will be entitled to receive an amount in cash (computed to the nearest cent) equal to the product of: (i) that same fraction; and (ii) the acquisition termination share price.

All cash payments to which a holder of our depositary shares is entitled upon redemption will be rounded to the nearest cent. We may, in our sole discretion, determine to redeem our Series B Preferred Stock represented by our depositary shares as described hereunder.

Other than pursuant to the redemption provisions described above, our depositary shares will not be redeemable. However, at our option, we may purchase our depositary shares from time to time in the open market, by tender offer or otherwise.

Voting Our Series B Preferred Stock

Because each depositary share represents a 1/20th interest in a share of our Series B Preferred Stock, holders of our depositary shares will be entitled to 1/20th of a vote per share of our Series B Preferred Stock under those circumstances in which holders of our Series B Preferred Stock are entitled to a vote.

When the depositary receives notice of any meeting at which the holders of our Series B Preferred Stock are entitled to vote, the depositary will send the notice to the record holders of our depositary shares relating to our Series B Preferred Stock. Each record holder of our depositary shares on the record date (which will be the same date as the record date for our Series B Preferred Stock) may instruct the depositary as to how to vote the amount of our Series B Preferred Stock represented by such holder’s depositary shares in accordance with these instructions. The depositary will endeavor insofar as practicable to vote or cause to be voted the amount of our Series B Preferred Stock represented by such depositary shares in accordance with these instructions, and we will take all actions the depositary deems necessary in order to enable the depositary to do so. The depositary will abstain from voting shares of our Series B Preferred Stock to the extent it does not receive specific instructions from the holders of our depositary shares representing our Series B Preferred Stock.

Modification and Amendment

Without the consent of the holders of our depositary shares, we may amend, alter or supplement the deposit agreement or any certificate representing our depositary shares for the following purposes:

• to cure any ambiguity, omission, inconsistency or mistake in any such agreement or instrument;

• to make any provision with respect to matters or questions relating to our depositary shares that is not inconsistent with the provisions of the deposit agreement and that does not adversely affect the rights, preferences, privileges or voting powers of any holder of our depositary shares;

• to make any change reasonably necessary, in our reasonable determination, to reflect each depositary share’s representation of 1/20th of a share of our Series B Preferred Stock;

• to make any change reasonably necessary, in our reasonable determination, to comply with the procedures of the depositary and that does not adversely affect the rights, preferences, privileges or voting powers of any holder of our depositary shares; or

• to make any other change that does not adversely affect the rights, preferences, privileges or voting powers of any holder of our depositary shares (other than any holder that consents to such change).

In addition, without the consent of the holders of our depositary shares, we may amend, alter, supplement or repeal any terms of our depositary shares to conform the terms of our depositary shares to the description thereof in the related prospectus as supplemented for our depositary shares, as further supplemented and/or amended by the related pricing term sheet.

Termination

The deposit agreement may be terminated by us or the depositary only if (a) all our outstanding depositary shares have been cancelled, upon conversion or redemption of our Series B Preferred Stock or otherwise, or (b) there has been made a final distribution in respect of our Series B Preferred Stock in connection with any liquidation, winding-up or dissolution of us and such distribution shall have been distributed to the record holders of our depositary shares pursuant to the deposit agreement.

Charges of Depositary

We will pay all transfer and other taxes and governmental charges arising solely from the existence of the depositary arrangements. We will pay all charges of the depositary in connection with the initial deposit of the shares of our Series B Preferred Stock. Holders of our depositary shares will pay other transfer and other taxes and governmental charges and any other charges, including a fee for the withdrawal of shares of our Series B Preferred Stock upon surrender of depositary receipts, as are expressly provided in the deposit agreement to be for their accounts.

Withdrawal Rights

A holder of 20 depositary shares may withdraw the share of our Series B Preferred Stock corresponding to such depositary shares, and any cash or other property represented by such depositary shares. A holder who withdraws shares of our Series B Preferred Stock (and any such cash or other property) will not be required to pay any taxes or duties relating to the issuance or delivery of such shares of our Series B Preferred Stock (and any such cash or other property), except that such holder will be required to pay any tax or duty that may be payable relating to any transfer involved in the issuance or delivery of such shares of our Series B Preferred Stock (and any such cash or other property) in a name other than the name of such holder. Holders of shares of our Series B Preferred Stock will not have the right under the deposit agreement to deposit such shares with the depositary in exchange for our depositary shares.

Listing

We have listed our depositary shares on The New York Stock Exchange under the symbol “CNPPRB.” No assurance can be given that our depositary shares will be listed or that any such application for listing will be approved.

Form and Notices

The shares of our Series B Preferred Stock will be issued in registered form to the depositary, and our depositary shares will be issued in book-entry only form through DTC prior to the conversion of our Series B Preferred Stock, as described under “—Book-Entry, Settlement and Clearance” in this section. The depositary will forward to the holders of our depositary shares all reports, notices, and communications from us that are delivered to the depositary and that we are required to furnish to the holders of our Series B Preferred Stock.

Book-Entry, Settlement and Clearance

The Global Security

Our depositary shares will be initially issued in the form of a single registered security in global form (the “global security”). Upon issuance, the global security will be deposited with the depositary as custodian for DTC and registered in the name of Cede & Co., as nominee of DTC.

Ownership of beneficial interests in the global security will be limited to persons who have accounts with DTC (“DTC participants”) or persons who hold interests through DTC participants. We expect that under procedures established by DTC:

• upon deposit of the global security with DTC’s custodian, DTC will credit portions of the global security to the accounts of the DTC participants designated by the underwriters; and

• ownership of beneficial interests in the global security will be shown on, and transfer of ownership of those interests will be effected only through, records maintained by DTC (with respect to interests of DTC participants) and the records of DTC participants (with respect to other owners of beneficial interests in the global security).

Beneficial interests in the global security may not be exchanged for securities in physical, certificated form except in the limited circumstances described below.

Book-Entry Procedures for the Global Security

All interests in the global security will be subject to the operations and procedures of DTC. We provide the following summary of those operations and procedures solely for the convenience of investors. The operations and procedures of DTC are controlled by that settlement system and may be changed at any time. Neither we nor the underwriters are responsible for those operations or procedures.

DTC has advised us that it is:

• a limited purpose trust company organized under the laws of the State of New York;

• a “banking organization” within the meaning of the New York State Banking Law;

• a member of the Federal Reserve System;

• a “clearing corporation” within the meaning of the Uniform Commercial Code; and

• a “clearing agency” registered under Section 17A of the Exchange Act.

DTC was created to hold securities for its participants and to facilitate the clearance and settlement of securities transactions between its participants through electronic book-entry changes to the accounts of its participants. DTC’s participants include securities brokers and dealers, including the underwriters; banks and trust companies; clearing corporations and other organizations. Indirect access to DTC’s system is also available to others such as banks, brokers, dealers and trust companies; these indirect participants clear through or maintain a custodial relationship with a DTC participant, either directly or indirectly. Investors who are not DTC participants may beneficially own securities held by or on behalf of DTC only through DTC participants or indirect participants in DTC.

So long as DTC’s nominee is the registered owner of the global security, that nominee will be considered the sole owner or holder of our depositary shares represented by the global security for all purposes under the deposit agreement. Except as provided below, owners of beneficial interests in the global security:

• will not be entitled to have securities represented by the global security registered in their names;

• will not receive or be entitled to receive physical, certificated securities; and

• will not be considered the owners or holders of the securities under the deposit agreement for any purpose, including with respect to the giving of any direction, instruction or approval to the depositary under the deposit agreement.

As a result, each investor who owns a beneficial interest in the global security must rely on the procedures of DTC to exercise any rights of a holder of securities under the deposit agreement (and, if the investor is not a participant or an indirect participant in DTC, on the procedures of the DTC participant through which the investor owns its interest).

Payments of dividends with respect to our depositary shares represented by the global security will be made by the depositary to DTC’s nominee as the registered holder of the global security. Neither we nor the depositary will have any responsibility or liability for the payment of amounts to owners of beneficial interests in the global security, for any aspect of the records relating to or payments made on account of those interests by DTC, or for maintaining, supervising or reviewing any records of DTC relating to those beneficial interests.

Payments by participants and indirect participants in DTC to the owners of beneficial interests in the global security will be governed by standing instructions and customary industry practice and will be the responsibility of those participants or indirect participants and DTC.

Transfers between participants in DTC will be effected under DTC’s procedures and will be settled in same-day funds.

Certificated Securities

Our depositary shares in physical, certificated form will be issued and delivered to each person that DTC identifies as a beneficial owner of our depositary shares only if:

• DTC notifies us at any time that it is unwilling or unable to continue as depositary for the global security and a successor depositary is not appointed within 90 days; or

• DTC ceases to be registered as a clearing agency under the Exchange Act and a successor depositary is not appointed within 90 days.

EX-4.II

Exhibit 4(ii)

DESCRIPTION OF CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC’S SECURITIES

REGISTERED PURSUANT TO SECTION 12

OF THE SECURITIES EXCHANGE ACT OF 1934

As of December 31, 2019, CenterPoint Energy Houston Electric, LLC has two classes of securities registered under Section 12 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”): (1) our 6.95% general mortgage bonds due 2033 (“General Mortgage Bonds”) and (2) our 9.15% first mortgage bonds due 2021 (“First Mortgage Bonds”). As used in this Exhibit 4(ii), the terms “CenterPoint Energy Houston Electric, LLC,” “us,” “we” or “our” refer to CenterPoint Energy Houston Electric, LLC and not any of its subsidiaries.

DESCRIPTION OF OUR GENERAL MORTGAGE BONDS

The following description of our General Mortgage Bonds is a summary and does not purport to be complete. It is subject to and qualified in its entirety by reference to our General Mortgage Indenture dated as of October 10, 2002 with The Bank of New York Mellon Trust Company, N.A. (successor in trust to JPMorgan Chase Bank), as trustee, as amended and supplemented, in the case of the General Mortgage Bonds, by the Tenth Supplemental Indenture, dated as of March 18, 2003,each of which are incorporated by reference as an exhibit to the Annual Report on Form 10-K of which this Exhibit 4(ii) is a part. We encourage you to read the above referenced General Mortgage Indenture and Tenth Supplemental Indenture for additional information.

General

The bonds were issued under the General Mortgage Indenture (the “indenture”), dated as of October 10, 2002, between us and JPMorgan Chase Bank, as trustee (the “trustee”), as amended and supplemented. The descriptions under this heading and the heading “The Indenture” are summaries of the material provisions of the bonds and the indenture. Such summaries do not purport to be complete and are qualified in their entirety by reference to the indenture and the bonds. References to article and section numbers in this offering memorandum, unless otherwise indicated, are references to article and section numbers of the indenture.

The bonds will bear interest at the rate of 6.95% per annum. Interest on the bonds is payable semi-annually in arrears on each March 15 and September 15 (each an “interest payment date”), commencing September 15, 2003, to the persons in whose names they are registered at the close of business on the fifteenth calendar day preceding each interest payment date; provided, however, that interest payable at maturity (whether at stated maturity, upon redemption or otherwise) will be payable to the registered bondholder to whom principal is payable.

The bonds mature on March 15, 2033. The bonds are subject to optional redemption before their maturity as described below. They are not entitled to the benefit of any sinking fund.

Interest

Interest on the bonds will be payable on each interest payment date for the period commencing on the next preceding interest payment date (or if no interest has been paid thereon, commencing on the date of issuance thereof) to, but not including, such interest payment date.

If any interest payment date or the date of maturity falls on a day that is not a business day, all payments to be made on such day shall be made on the next succeeding business day with the same force and effect as if made on the due date, and no additional interest shall be payable as a result of such delay in payment. Interest will be computed on the basis of a 360-day year of twelve 30-day months.

Any interest payable on any interest payment date other than maturity and not so punctually paid or duly provided for will cease to be payable to the person in whose name the bond is registered at the close of business on the applicable regular record date and will instead be payable to the person in whose name the bond (or one or more predecessor bonds) is registered at the close of business on a special record date for the payment of such interest to be fixed by us, notice of which will be given to the registered holder of the bond (or one or more predecessor bonds) not less than 10 days prior to such special record date. (See Section 307)

Payment of Bonds; Transfers; Exchanges

Interest, if any, on bonds payable on each interest payment date will be paid to the person in whose name such bond is registered (the registered holder of any indenture bond being hereinafter called a “holder”) as of the close of business on the regular record date relating to such interest payment date; provided, however, that interest payable at maturity will be paid to the person to whom principal is paid. However, if there has been a default in the payment of interest on any bond, such defaulted interest may be payable to the holder of such bond as of the close of business on a date selected by the trustee which is not more than 15 days or less than 10 days prior to the date proposed by us for payment of such defaulted interest and not less than 10 days after the receipt by the trustee of the notice of the proposed payment or in any other lawful manner not inconsistent with the requirements of any securities exchange on which such bond may be listed, if the trustee deems such manner of payment practicable. (See Section 307)

The principal of and premium, if any, and interest on the bonds at maturity will be payable upon presentation of the bonds at the corporate trust office of JPMorgan Chase Bank in Houston, Texas as paying agent for us. We may change the place of payment on the bonds, may appoint one or more additional paying agents (including us) and may remove any paying agent, all at our discretion. (See Section 602)

The transfer of bonds may be registered, and bonds may be exchanged for other bonds of the same series, of authorized denominations and of like tenor and aggregate principal amount, at the corporate trust office of JPMorgan Chase Bank in Houston, Texas, as bond registrar for the bonds. We may change the place for registration of transfer and exchange of the bonds, and may designate one or more additional places for such registration and exchange, all at our discretion. (See Sections 602 and 305) No service charge will be made for any registration of transfer or exchange of the bonds; however, we may require payment of a sum sufficient to cover any tax or other governmental charge that may be imposed in connection with any registration of transfer or exchange of bonds. We will not be required to execute or to provide for the registration of transfer of or the exchange of:

• any bond during a period of 15 days prior to giving any notice of redemption; or

• any bond selected for redemption, in whole or in part, except the unredeemed portion of any bond being redeemed in part. (See Section 305)

All moneys paid by us to a paying agent or the trustee (or held by us in trust) for the payment of the principal of or any premium or interest on a bond which remain unclaimed at the end of two years after such principal, premium or interest has become due and payable will be repaid to us at our request, and the holder of such bond thereafter may, as an unsecured general creditor, look only to us for payment thereof, and all liability of the paying agent, the trustee and us (as trustee) with respect thereto shall thereupon cease. (See Section 603)

Optional Redemption

The bonds may be redeemed in whole at any time or in part from time to time, at our option, at a redemption price equal to the greater of:

• 100% of the principal amount of the bonds then outstanding to be redeemed; or

• the sum of the present values of the remaining scheduled payments of principal and interest on the bonds to be redeemed (not including any portion of such payments of interest accrued to the date of redemption) discounted to the date of redemption on a semiannual basis (assuming a 360-day year consisting of twelve 30-day months) at the applicable treasury rate plus 35 basis points;

plus, in each case, accrued and unpaid interest on the principal amount being redeemed to the redemption date.

“treasury rate” means, with respect to any redemption date:

• the yield, under the heading which represents the average for the immediately preceding week, appearing in the most recently published statistical release designated “H.15 (519)” or any successor publication which is published weekly by the Board of Governors of the Federal Reserve System and which establishes yields on actively traded U.S. Treasury securities adjusted to constant maturity under the caption “Treasury Constant Maturities,” for the maturity corresponding to the comparable treasury issue (if no maturity is within three months before or after the remaining life (as defined below), yields for the two published maturities most closely corresponding to the comparable treasury issue will be determined and the treasury rate will be interpolated or extrapolated from such yields on a straight line basis, rounding to the nearest month); or

• if such release (or any successor release) is not published during the week preceding the calculation date or does not contain such yields, the rate per annum equal to the semiannual equivalent yield to maturity of the comparable treasury issue, calculated using a price for the comparable treasury issue (expressed as a percentage of its principal amount) equal to the comparable treasury price for such redemption date.

The treasury rate will be calculated on the third business day preceding the date fixed for redemption.

“comparable treasury issue” means the U.S. Treasury security selected by an independent investment banker as having a maturity comparable to the remaining term (“remaining life”) of the bonds to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of such notes.

“comparable treasury price” means (1) the average of five reference treasury dealer quotations for such redemption date, after excluding the highest and lowest reference treasury dealer quotations, or (2) if the independent investment banker obtains fewer than four such reference treasury dealer quotations, the average of all such quotations.

“independent investment banker” means Credit Suisse First Boston LLC, Deutsche Bank Securities Inc. or Salomon Smith Barney Inc., as specified by us, or, if these firms are unwilling or unable to select the comparable treasury issue, an independent investment banking institution of national standing appointed by us.

“reference treasury dealer” means (1) Credit Suisse First Boston LLC, Deutsche Bank Securities Inc. and Salomon Smith Barney Inc. and their respective successors, provided, however, that if any of the foregoing shall cease to be a primary U.S. government securities dealer in New York City (a “primary treasury dealer”), we will substitute therefor another primary treasury dealer and (2) any other primary treasury dealer selected by us after consultation with the independent investment banker.

“reference treasury dealer quotations” means, with respect to each reference treasury dealer and any redemption date, the average, as determined by the independent investment banker, of the bid and asked prices for the comparable treasury issue (expressed in each case as a percentage of its principal amount) quoted in writing to the independent investment banker at 5:00 p.m., New York City time, on the third business day preceding such redemption date.

The trustee will mail a notice of redemption to each holder of bonds to be redeemed by first-class mail at least 30 and not more than 60 days prior to the date fixed for redemption. Unless we default on payment of the redemption price, interest will cease to accrue on the bonds or portions thereof called for redemption. If fewer than all of the bonds are to be redeemed, the trustee will select, not more than 60 days prior to the redemption date, the particular bonds or portions thereof for redemption from the outstanding bonds not previously called by such method as the trustee deems fair and appropriate.

THE INDENTURE

Security

Except as otherwise contemplated below under this heading and subject to the exceptions specifically discussed under “—Release of Property” and “—Defeasance,” all outstanding indenture bonds, will be secured, equally and ratably, by the lien of the indenture on substantially all properties owned by us (and not excepted or released from the lien thereof), and improvements, extensions and additions to, and renewals and replacements of, such properties (the “mortgaged property”). The lien of the indenture will be junior, subject and subordinate to the lien of our existing first mortgage indenture.

The term “first mortgage indenture” means the Mortgage and Deed of Trust, dated as of November 1, 1944, from our predecessor in interest, Houston Lighting & Power Company, to JPMorgan Chase Bank (successor to South Texas Commercial National Bank of Houston), as trustee, as heretofore and hereafter amended and supplemented and “first mortgage bonds” means the first mortgage bonds issued thereunder.

The indenture provides that, after the issuance of the initial series of bonds under the indenture and until the first mortgage collateralization date (as defined at the end of this section), we will not issue any additional first mortgage bonds under the first mortgage indenture, except:

• first mortgage bonds in place of, and in substitution for, or to refund, other first mortgage bonds, if (A) the aggregate principal amount of such new first mortgage bonds shall not exceed the aggregate principal amount of such other first mortgage bonds, and (B) the final stated maturity date of such new first mortgage bonds shall be a date not later than the final stated maturity date of such other first mortgage bonds;

• as necessary to replace any mutilated, lost or destroyed first mortgage bonds or to effect exchanges and transfers of first mortgage bonds; and

• if at any time first mortgage bonds are issued pursuant to the first bullet point above, additional first mortgage bonds in an aggregate principal amount of up to $118 million for the purpose of satisfying the requirement under the indentures pursuant to which certain pollution control bonds were issued by various governmental authorities (which indentures provide that, if we issue first mortgage bonds in certain circumstances, we also are required to issue first mortgage bonds to secure such pollution control bonds on an equal and ratable basis). (See Section 611)

At any time, in our discretion, we may issue and deliver to the trustee as security under the indenture first mortgage bonds in an aggregate principal amount equal to the aggregate principal amount of indenture bonds then outstanding; provided that such first mortgage bonds (the “first mortgage collateral bonds”) shall:

• have terms of payment equivalent to those of such indenture bonds;

• provide that payments by us in respect of principal, premium, if any, or interest due under the indenture bonds will offset our equivalent payment obligations under the first mortgage collateral bonds; and

• provide for the mandatory redemption of the first mortgage collateral bonds upon acceleration of the maturity of such indenture bonds. (See Section 701)

The date on which such first mortgage collateral bonds are delivered to the trustee is referred to herein as the “first mortgage collateralization date.”

Lien of the Indenture

General. The indenture constitutes a lien on substantially all our real property and tangible personal property, other than property excepted from such lien and such property as may be released from such lien in accordance with the terms of the indenture, subject to no liens prior to the lien of the indenture other than the lien of the first mortgage indenture (so long as the same remains in effect) and other liens permitted to exist.

Permitted liens and certain other liens permitted to exist. The indenture provides that after-acquired property (other than excepted property) will be subject to the lien of the indenture; provided, however, that in the case of our consolidation or merger into another entity or transfer of the mortgaged property as or substantially as an entirety, the indenture will not be required to be a lien upon any of the properties then owned or thereafter acquired by the successor entity except properties acquired from us in or as a result of such transaction, and improvements, extensions and additions to such properties and renewals, replacements and substitutions of or for any part or parts thereof and that in the case of a consolidation or merger with respect to which we are the surviving entity, the indenture will not be required to be a lien on any properties acquired by us in or as a result of such transaction or any improvements, extensions or additions to such properties or any renewals, replacements or substitutions of or for any part or parts thereof. (See Article Thirteen) See “—Consolidation, Merger, Etc.” below. In addition, after-acquired property may be subject to liens existing or placed thereon at the time of acquisition thereof, including, but not limited to, purchase money liens.

Without the consent of the holders, we and the trustee may enter into supplemental indentures in order to subject to the lien of the indenture additional property (including property which would otherwise be excepted from such lien). (See Section 1401) Such property would thereupon constitute property additions (so long as it would otherwise qualify as property additions as described below) and be available as a basis for the issuance of indenture bonds. See “—Issuance of Indenture Bonds.”

Excepted Property. There are excepted from the lien of the indenture, among other things:

• cash, deposit accounts, shares of stock, interests in general or limited partnerships, securities not deposited with or held by the trustee;

• contracts, leases and other agreements of all kinds;

• contract rights, bills, notes and other instruments and chattel paper;

• revenues, income and earnings, accounts and accounts receivable and unbilled revenues, rents, tolls, issues, product and profits, claims, demands and judgments;

• governmental and other licenses, permits, franchises, consents and allowances (except to the extent that any of the same constitute rights or interests relating to the occupancy or use of real property);

• certain intellectual property rights, domain names and other general intangibles;

• vehicles, movable equipment and aircraft and supplies used in connection with the foregoing;

• all goods, stock in trade, wares, merchandise and inventory held for sale or lease in the ordinary course of business;

• materials, supplies, inventory and other personal property consumable in the operation of the mortgaged property; fuel; portable tools and equipment; furniture and furnishings;

• computers and data processing, telecommunications and certain other facilities and equipment used primarily for administrative or clerical purposes or not otherwise necessary for the operation or maintenance of facilities and equipment for the generation, transmission and distribution of electric energy and our other buildings and improvements;

• coal, ore, gas, oil and other minerals and timber;

• electric energy, gas (natural or artificial), steam, water and other products generated, produced, manufactured, purchased or otherwise acquired by us;

• real property, gas wells, pipelines, and other facilities used or to be used for the production, gathering, transmission, storage or distribution of natural gas, crude oil or other hydrocarbons or minerals;

• leasehold interests held by us as lessee;

• facilities and equipment for the storage, transmission and distribution of water; and

• other property excepted from or released from the lien of the first mortgage indenture prior to the date of the indenture. (See “Excepted Property” under “Granting Clauses” in the indenture and “Granting Clauses” in the first mortgage indenture.)

Permitted liens. The lien of the indenture is subject to permitted liens and certain other liens permitted to exist. Under the indenture, permitted liens include the following, among other, liens:

• liens for taxes which are not delinquent or are being contested in good faith or which secure charges that do not exceed $5,000,000;

• mechanics’, workmen’s and similar liens and certain other liens arising in the ordinary course of business;

• liens in respect of judgments:

• in an amount not exceeding the greater of $10 million and 3% of the sum of the then outstanding aggregate principal amount of indenture bonds and first mortgage bonds other than first mortgage collateral bonds then outstanding; or

• with respect to which we shall in good faith be prosecuting an appeal or shall have the right to do so;

• easements, leases or other rights of others in, and defects in title to, the mortgaged property which do not in the aggregate materially impair the use by us of the mortgaged property considered as a whole;

• defects, irregularities and limitations in title to real property subject to rights-of-way in our favor or used primarily for right-of-way purposes;

• liens securing indebtedness and other obligations of others upon real property existing at the date of the indenture or at the time of our acquisition of such property;

• leases existing at the date of the indenture and subsequent leases for not more than 15 years or which do not materially impair our use of the property subject thereto;

• liens of lessors or licensors for amounts due which are not delinquent or are being contested in good faith;

• controls, restrictions or obligations imposed by governmental authorities upon the mortgaged property or the operation thereof;

• rights of governmental authorities to purchase or designate a purchaser of the mortgaged property;

• liens required by law or governmental regulation as a condition to the transaction of any business or the exercise of any privilege or license, or to enable us to maintain self-insurance or to participate in any funds established to cover insurance risks or in connection with workmen’s compensation, unemployment insurance, social security or any pension or welfare benefit plan or program;

• liens to secure the performance of duties or public or statutory, bid or performance obligations or surety, stay or appeal bonds;

• rights of others to take minerals, timber, electric energy, gas, water, steam or other products produced by us or by others on our property;

• rights and interests of persons other than us arising out of agreements to which we are a party relating to the common ownership or joint use of property, and liens on the interests of such persons in such property;

• restrictions on assignment and/or qualification requirements on the assignee;

• liens which have been bonded for the full amount in dispute or for the payment of which other security arrangements have been made;

• easements, ground leases or rights-of-way on or across our property for the purpose of roads, pipelines, transmission or distribution lines, communication lines, railways and other similar purposes, provided that the same do not materially impair the use by us of such property or rights-of-way;

• liens on our air or water pollution control, sewage or solid waste disposal or other similar facilities in connection with the issuance of pollution control revenue bonds, in connection with financing the cost of, or construction, acquisition, improvement, repair or maintenance of, such facilities;

• the trustee’s lien specified below;

• prepaid liens; and

• the lien of the first mortgage indenture. (See Granting Clauses and Section 101)

“Prepaid lien” means generally any lien securing indebtedness for the payment or redemption of which there shall have been irrevocably deposited in trust with the trustee or other holder of such lien moneys and/or investment securities which (together with the interest reasonably expected to be earned from the investment and reinvestment in investment securities of the moneys and/or the principal of and interest on the investment securities so deposited) shall be sufficient for such purpose; provided, however, that the first mortgage indenture shall not be deemed to be a prepaid lien unless it shall have been satisfied and discharged and all first mortgage bonds issued thereunder shall be deemed to have been paid, all in accordance with the provisions thereof. (See Section 101)

Trustee’s Lien. The indenture provides that the trustee will have a lien, prior to the lien on behalf of the holders of indenture bonds, upon the mortgaged property for the payment of its reasonable compensation and expenses and for indemnity against certain liabilities. (See Section 1107)

Issuance of Indenture Bonds

The aggregate principal amount of indenture bonds that may be authenticated and delivered under the indenture is unlimited. (See Section 301). Indenture bonds of any series may be issued from time to time, provided that the first mortgage collateralization date has not occurred, on the basis of property additions, retired bonds (as such terms are defined below) and cash deposited with the trustee, and in an aggregate principal amount not exceeding:

• 70% of the cost (as defined below) or fair value (as defined below) (whichever is less) of property additions (as described below) that do not constitute funded property (as defined below) after certain deductions and additions, primarily including adjustments to offset property retirements;

• the aggregate principal amount of retired bonds; and

• an amount of cash deposited with the trustee. (See Article Four)

In addition, any issuance of indenture bonds after March 31, 2003, other than any issuance on the basis of retired bonds having an applicable interest rate not less than the interest rate applicable to the indenture bonds to be issued, requires that we provide a certificate demonstrating that the adjusted net earnings (as defined below) for the specified 12 month period are not less than 200% of the annual interest requirements (as defined below) for the specified one year period.

“Adjusted net earnings” means the amount for a period of 12 consecutive calendar months within the 18 calendar months immediately preceding the first day of the month in which we intend to issue additional indenture bonds (or, in the case of any such certificate to be delivered on or prior to June 30, 2003, for a period of 12 consecutive calendar months within the 15 calendar months immediately preceding the first day of such month):

• our operating revenues for such period; minus

• our operating expenses, excluding:

• expenses for taxes on income or profits;

• provisions for reserves for depreciation, amortization, depletion or retirement of property;

• interest expense, including the amortization of debt discount, premium, expense or loss on reacquired debt, for any replacement, sinking fund or other device for the retirement or amortization of any indebtedness;

• non-recurring charge or expenses; and

• provisions for any refund of our revenues previously collected or accrued; plus

• our other income, net of related expenses (excluding expenses or provisions for any non-recurring charges).

“Annual interest requirements” means the interest requirements for one year, at the respective stated interest rates, if any, borne before maturity, upon:

• all outstanding indenture bonds, except any for the payment or redemption of which indenture bonds applied for are to be issued;

• all indenture bonds then applied for in pending applications for the original issuance of indenture bonds, including the application in connection with which such certificate is made;

• all outstanding first mortgage bonds, except any for the payment or redemption of which the indenture bonds applied for are to be issued; and

• the principal amount of all other indebtedness, except:

• first mortgage collateral bonds;

• our indebtedness, the repayment of which supports or is supported by other indebtedness included in annual interest requirements pursuant to one of the other clauses of this definition;

• indebtedness for the payment of which the indenture bonds applied for are to be issued; and

• indebtedness secured by a prepaid lien prior to the lien of the indenture upon property subject to such lien, outstanding on the date of such computation and secured by a lien on a parity with or prior to the lien of the indenture upon property subject to the lien of the indenture, if such indebtedness has been issued, assumed or guaranteed by us or if we customarily pay the interest upon the principal thereof or collections from our customers are applied to, or pledged as security for the payment of such interest;

provided, however, that if any such indebtedness bears interest at a variable rate, then the interest requirement on such indebtedness shall be determined by reference to the rate in effect on the day immediately preceding the date of such computation; and provided, further, that any amounts collected by others to be applied to debt service on our indebtedness, and not otherwise treated on our books as revenue, shall be added to our operating revenues when determining adjusted net earnings.

“Cost” with respect to property additions generally means the sum of:

• any cash paid in the acquisition of such property;

• an amount equivalent to the fair market value in cash of any securities or other property paid in the acquisition of such property;

• the principal amount of any obligations secured by prior lien (other than the lien of the first mortgage indenture) upon such property additions outstanding at the time of the acquisition thereof;

• the principal amount of any other obligations incurred or assumed in connection with the payment for such property additions or for the acquisition thereof; and

• any other amounts which, in accordance with generally accepted accounting principles, are properly charged or chargeable to our plant or other property accounts with respect to such property additions as part of the cost of construction or acquisition thereof, including, but not limited to any allowance for funds used during construction or any similar or analogous amount;

• provided, however, that:

• with respect to property additions owned by our successor immediately prior to the time it shall have become such successor in or as a result of an acquisition, consolidation or merger, cost shall mean the amount or amounts at which such property additions are recorded in the plant or other property accounts of such successor, or the predecessor from which such property additions are acquired, as the case may be, immediately prior to such consolidation or merger;

• with respect to property additions which shall have been acquired (otherwise than by construction) by us without any consideration consisting of cash, securities or other property or the incurring or assumption of indebtedness or other obligation, no determination of cost shall be required and, wherever provision is made for cost or fair value, cost with respect to such property additions shall mean an amount equal to the fair value to us thereof or, if greater, the aggregate amount reflected in our books of account with respect thereto upon the acquisition thereof; and

• in no event shall the cost of property additions be required to reflect any depreciation or amortization in respect of such property additions, or any adjustment to the amount or amounts at which such property additions are recorded in plant or other property accounts due to the non-recoverability of investment or otherwise.

If any property additions include property which has been used or operated by third parties in a business similar to that in which it has been or is to be used or operated by us, the cost thereof need not be reduced by any amount in respect of any goodwill, going concern value rights and/or intangible property simultaneously acquired and in such case the term property additions as defined herein may include such goodwill, going concern value rights and intangible property.

“Fair value,” with respect to property, generally means the fair value of such property as may reasonably be determined by reference to:

• the amount which would be likely to be obtained in an arm’s-length transaction with respect to such property between an informed and willing buyer and an informed and willing seller, under no compulsion, respectively, to buy or sell;

• the amount of investment with respect to such property which, together with a reasonable return thereon, would be likely to be recovered through ordinary business operations or otherwise;

• the cost, accumulated depreciation and replacement cost with respect to such property; and/or

• any other relevant factors; provided, however, that:

• the fair value of property shall be determined without deduction for any liens on such property prior to the lien of the indenture; and

• the fair value of property additions shall not reflect any reduction relating to the fact that such property additions may be of less value to a person which is not the owner or operator of the mortgaged property or any portion thereof than to the owner or operator. Fair value may be determined, in the discretion of the expert certifying the same, without physical inspection, by the use of accounting and/or engineering records and/or other data maintained by us or otherwise available to such expert.

“Funded property” generally includes property additions which have been designated funded property in an expert’s certificate, which have been made the basis of the authentication and delivery of indenture bonds, which have been made the basis for the release of mortgaged property, which have been made the basis for the withdrawal of cash, which have been substituted for retired funded property or which have been used for other specified purposes. (See Section 102)

“Property additions” generally include any property which is owned by us and is subject to the lien of the indenture except (with certain exceptions) goodwill, going concern value rights or intangible property, or any property the cost of acquisition or construction of which is properly chargeable to one of our operating expense accounts. (See Section 103)

“Retired bonds” means, generally:

• indenture bonds which are no longer outstanding under the indenture, which have not been retired by the application of funded cash and which have not been used as the basis for the authentication and delivery of indenture bonds, the release of property or the withdrawal of cash; and

• certain first mortgage bonds issued under the first mortgage indenture which could be used as a basis for the authentication and delivery of additional first mortgage bonds under the first mortgage indenture and have been retired after the initial issuance of indenture bonds under the indenture;

provided, however, that no first mortgage bond may be used as the basis for the authentication and delivery of both additional indenture bonds and additional first mortgage bonds. (See Section 101).

Release of Property

Unless an event of default (as defined below) has occurred and is continuing, we may obtain the release from the lien of the indenture of any funded property upon delivery to the trustee of certain certificates and an amount in cash equal to the amount, if any, by which 70% of the cost of the property to be released (or, if less, the fair value of such property at the time it became funded property) exceeds the aggregate of:

• an amount equal to 70% of the aggregate principal amount of obligations secured by purchase money liens delivered to the trustee, subject to certain limitations described below;

• an amount equal to 70% of the cost or fair value (whichever is less) of certified property additions not constituting funded property after certain deductions and additions, primarily including adjustments to offset property retirements (except that such adjustments need not be made if such property additions were acquired or made within the 90-day period preceding the release);

• the aggregate principal amount of indenture bonds we would be entitled to issue on the basis of retired bonds (with such entitlement being waived by operation of such release);

• any amount of cash and/or an amount equal to 70% of the aggregate principal amount of obligations secured by purchase money liens upon the property released delivered to the trustee or other holder of a lien prior to the lien of the indenture, subject to certain limitations described below;

• on or after the first mortgage collateralization date, the aggregate principal amount of first mortgage bonds delivered to the trustee to be held as first mortgage collateral bonds;

• the aggregate principal amount of outstanding indenture bonds delivered to the trustee (with such indenture bonds to be canceled by the trustee); and

• any taxes and expenses incidental to any sale, exchange, dedication or other disposition of the property to be released. (See Section 803)

As used in the indenture, the term “purchase money lien” means, generally, a lien on the property being acquired, disposed of by us or being released from the lien of the indenture, which is taken or retained by the transferor of such property to secure all or part of the purchase price thereof or granted to one or more other persons (other than the transferor) who by making advances or incurring an obligation, give value to enable the grantor of the lien to acquire rights in such property, or granted to another person in connection with the release of property from the lien of the indenture on the basis of a deposit with the trustee or other holder of a lien prior to the lien of the indenture of obligations secured by such lien on such property, or held by a trustee or agent for the benefit of any such persons, and may include liens which cover property in addition to the property being released and/or which secure indebtedness in addition to indebtedness to the transferor of such property. (See Section 101) Generally, the principal amount of obligations secured by purchase money liens used as the basis for the release of property may not exceed 75% of the fair value of such property unless no additional obligations are outstanding, or are permitted to be issued, under such purchase money lien. (See Section 803)

Property which is not funded property may generally be released from the lien of the indenture without depositing any cash or property with the trustee as long as:

• the aggregate amount of cost or fair value (whichever is less) of all property additions which do not constitute funded property (excluding the property to be released) after certain deductions and additions, primarily including adjustments to offset property retirements, is not less than zero; or

• the cost or fair value (whichever is less) of property to be released does not exceed the aggregate amount of the cost or fair value (whichever is less) of property additions acquired or made within the 90-day period preceding the release. (See Section 804)

The indenture provides simplified procedures for the release of minor properties and property taken by eminent domain, and provides for dispositions of certain obsolete property and grants or surrender of certain rights without any release or consent by the trustee. (See Sections 802, 805, 807 and 808)

If we retain any interest in any property released from the lien of the indenture, the indenture will not become a lien on such property or such interest therein or any improvements, extensions or additions to such property or renewals, replacements or substitutions of or for such property or any part or parts thereof. (See Section 809)

Withdrawal of Cash

Unless an event of default has occurred and is continuing and subject to certain limitations, cash held by the trustee may, generally:

• be withdrawn by us:

• to the extent of an amount equal to 70% of the cost or fair value to us (whichever is less) of property additions not constituting funded property, after certain deductions and additions, primarily including adjustments to offset retirements (except that such adjustments need not be made if such property additions were acquired or made within the 90-day period preceding the withdrawal); or

• in an amount equal to the aggregate principal amount of indenture bonds that we would be entitled to issue on the basis of retired bonds (with the entitlement to such issuance being waived by operation of such withdrawal); or

• on or after the first mortgage collateralization date, in an amount equal to the aggregate principal amount of first mortgage bonds delivered to the trustee to be held as first mortgage collateral bonds; or

• in an amount equal to the aggregate principal amount of outstanding indenture bonds delivered to the trustee; or

• upon our request, be applied to the purchase of indenture bonds or the payment (or provision therefor) at stated maturity of any indenture bonds or the redemption (or provision therefor) of any indenture bonds which are redeemable. (See Section 806)

Consolidation, Merger, Etc.

We may not consolidate with or merge into any other entity or convey, transfer or lease, subject to the lien of this indenture, the mortgaged property as or substantially as an entirety to any entity unless:

• the entity formed by such consolidation or into which we are merged or the entity which acquires by conveyance or transfer, or which leases, the mortgaged property as or substantially as an entirety is an entity organized and existing under the laws of the United States, or any State or Territory thereof or the District of Columbia; and

• such entity executes and delivers to the trustee a supplemental indenture that:

• in the case of a consolidation, merger, conveyance or other transfer, or in the case of a lease if the term thereof extends beyond the last stated maturity of the indenture bonds then outstanding, contains an express assumption by such entity of the due and punctual payment of the principal of and premium, if any, and interest, if any, on the indenture bonds and the performance of all of our covenants and conditions under the indenture; and

• in the case of a consolidation, merger, conveyance or other transfer, contains a grant, conveyance, transfer and mortgage by such entity:

• confirming the lien of the indenture on the mortgaged property; and

• subjecting to such lien all property thereafter acquired by such entity that shall constitute an improvement, extension or addition to the mortgaged property or renewal, replacement or substitution of or for any part thereof and, at the election of such entity, subjecting to the lien of the indenture such other property then owned or thereafter acquired by such entity as such entity shall specify; and

• in the case of a lease, such lease is made expressly subject to termination by us or by the trustee at any time during the continuance of an event of default; and

• immediately after giving effect to such transaction, no event of default and no event which, with notice or lapse of time or both, would become an event of default shall have occurred and be continuing. (See Section 1301)

In the case of the conveyance or other transfer of the mortgaged property as or substantially as an entirety to any other entity, upon the satisfaction of all the conditions described above, we would be released and discharged from all obligations under the indenture and on the indenture bonds then outstanding unless we elect to waive such release and discharge. (See Section 1304). For purposes of this section, “entity” means a corporation, limited liability company, company, association, joint-stock company, partnership, limited liability partnership, joint venture, trust, unincorporated organization or governmental authority.

Modification of Indenture

Modifications without Consent. Without the consent of any holders, we and the trustee may enter into one or more supplemental indentures for any of the following purposes, among others:

• to evidence the succession of another entity to us and the assumption by any such successor of our covenants and agreements in the indenture and in the indenture bonds; or

• to add one or more covenants or other provisions for the benefit of all holders or for the benefit of the holders of, or to remain in effect only so long as there shall be outstanding, indenture bonds of one or more specified series (for the purposes of this subsection, “series” includes tranches thereof), or to surrender any right or power conferred upon us by the indenture; or

• to correct or amplify the description of any property at any time subject to the lien of the indenture; or better to assure, convey and confirm to the trustee any property subject or required to be subjected to the lien of the indenture; or to subject to the lien of the indenture additional property (including property of others); to specify any additional permitted liens with respect to such additional property and to modify the provisions in the indenture for dispositions of certain types of property without release in order to specify any additional items with respect to such additional property; or

• to establish the form or terms of the indenture bonds of any series as permitted by the indenture; or

• to provide for the authentication and delivery of bearer bonds and coupons appertaining thereto representing interest, if any, thereon and for the procedures for the registration, exchange and replacement thereof and for the giving of notice to, and the solicitation of the vote or consent of, the holders thereof, and for any and all other matters incidental thereto; or

• to evidence and provide for the acceptance of appointment by a successor trustee or by a co-trustee; or

• to provide for the procedures required to permit the utilization of a non-certificated system of registration for all, or any series of, the indenture bonds; or

• to change any place or places where:

• the principal of and premium, if any, and interest, if any, on all or any series of indenture bonds will be payable;

• all or any series of indenture bonds may be surrendered for registration of transfer;

• all or any series of indenture bonds may be surrendered for exchange; and

• notices and demands to or upon us in respect of all or any series of indenture bonds and the indenture may be served; or

• to comply with the rules of any securities exchange on which any series of indenture bonds may be listed; or

• to modify this indenture to comply with the Trust Indenture Act of 1939, as amended (the “Trust Indenture Act”); or

• to cure any ambiguity, to correct or supplement any provision therein which may be defective or inconsistent with any other provision therein, or to make any other additions to, deletions from or other changes to the provisions thereof; provided that such additions, deletions and/or other changes do not adversely affect the interests of the holders of indenture bonds of any series in any material respect. (See Section 1401)

Without limiting the generality of the foregoing, if the Trust Indenture Act is amended after the date of the indenture in such a way as to require changes to the indenture or the incorporation therein of additional provisions or so as to permit changes to, or the elimination of, provisions which, at the date of the indenture or at any time thereafter, were required by the Trust Indenture Act to be contained in the indenture, the indenture will be deemed to have been amended so as to conform to such amendment or to effect such changes or elimination, and we and the trustee may, without the consent of any holders, enter into one or more supplemental indentures to evidence or effect such amendment. (See Section 1401)

Modifications Requiring Consent. Except as provided above, the consent of the holders of not less than a majority in aggregate principal amount of the indenture bonds of all series then outstanding, considered as one class, is required for the purpose of adding any provisions to, or changing in any manner, or eliminating any of the provisions of, the indenture pursuant to one or more supplemental indentures; provided, however, that if less than all of the series of indenture bonds outstanding are directly affected by a proposed supplemental indenture, then the consent only of the holders of a majority in aggregate principal amount of outstanding indenture bonds of all series so directly affected, considered as one class, will be required; and provided, further, that if the indenture bonds of any series have been issued in more than one tranche and if the proposed supplemental indenture directly affects the rights of the holders of one or more, but less than all such tranches, then the consent only of the holders of a majority in aggregate principal amount of the outstanding indenture bonds of all such tranches so directly affected, considered as one class, will be required; and provided, further, that no such amendment or modification may:

• change the stated maturity of the principal of, or any installment of principal of or interest on, any indenture bond, or reduce the principal amount thereof or the rate of interest thereon (or the amount of any installment of interest thereon) or change the method of calculating such rate or reduce any premium payable upon the redemption thereof, or reduce the amount of the principal of any discount bond or other indenture bond that would be due and payable upon a declaration of acceleration of maturity or change the coin or currency in which any indenture bond or any premium or the interest thereon is payable, or impair the right to institute suit for the enforcement of any such payment on or after the stated maturity of any indenture bond (or, in the case of redemption, on or after the redemption date) without, in any such case, the consent of the holder of such indenture bond;

• permit the creation of any lien (not otherwise permitted by the indenture) ranking prior to the lien of the indenture with respect to all or substantially all of the mortgaged property or terminate the lien of the indenture on all or substantially all of the mortgaged property or deprive the holders of the benefit of the lien of the indenture, without, in any such case, the consent of the holders of all indenture bonds then outstanding;

• reduce the percentage in principal amount of the outstanding indenture bonds of any series, or tranche thereof, the consent of the holders of which is required for any such supplemental indenture, or the consent of the holders of which is required for any waiver of compliance with any provision of the indenture or of any default thereunder and its consequences, or reduce the requirements for quorum or voting, without, in any such case, the consent of the holder of each outstanding indenture bond of such series; or

• modify any of the provisions (with certain exceptions) of the indenture relating to supplemental indentures, waivers of certain covenants and waivers of past defaults with respect to the indenture bonds without the consent of the holder of each outstanding indenture bond affected thereby.

A supplemental indenture that changes or eliminates any covenant or other provision of the indenture that has expressly been included solely for the benefit of the holders of, or that is to remain in effect only so long as there shall be outstanding, indenture bonds of one or more specified series or modifies the rights of the holders of indenture bonds of such series with respect to such covenant or other provision, will be deemed not to affect the rights under the indenture of the holders of the indenture bonds of any other series. (See Section 1402)

Waiver

The holders of at least a majority in aggregate principal amount of all indenture bonds may waive our obligations to comply with certain covenants, including the covenants to maintain our corporate or other legal existence and properties, pay taxes and discharge liens and maintain certain insurance and our covenant with respect to merger, consolidation or the transfer or lease of the mortgaged property as or substantially as an entirety, described above, provided that such waiver occurs before the time such compliance is required. The holders of at least a majority of the aggregate principal amount of outstanding indenture bonds of all affected series or tranches, considered as one class, may waive, before the time for such compliance, compliance with any covenant specified with respect to indenture bonds of such series or tranches thereof. (See Section 609) The holders of at least a majority in aggregate principal amount of all indenture bonds outstanding may waive past defaults, not including defaults in the payment of principal, premium or interest or defaults with respect to provisions that cannot be modified without the consent of each holder affected thereby, under the indenture. (See Section 1017)

Events of Default

Each of the following events constitutes an event of default under the indenture:

• failure to pay interest on any indenture bond within 30 days after the same becomes due and payable;

• failure to pay principal of or premium, if any, on any indenture bond when it becomes due and payable;

• failure to perform or breach of any of our covenants or warranties in the indenture (other than a covenant or warranty a default in the performance of which or breach of which is dealt with elsewhere under this paragraph) for a period of 90 days after there has been given to us by the trustee, or to us and the trustee by the holders of at least 33% in principal amount of outstanding indenture bonds, a written notice specifying such default or breach and requiring it to be remedied and stating that such notice is a “notice of default,” unless the trustee, or the trustee and the holders of a principal amount of indenture bonds not less than the principal amount of indenture bonds the holders of which gave such notice, as the case may be, agree in writing to an extension of such period prior to its expiration; provided, however, that the trustee, or the trustee and such holders, as the case may be, will be deemed to have agreed to an extension of such period if corrective action has been initiated by us within such period and is being diligently pursued;

• certain events relating to reorganization, bankruptcy and insolvency of us or appointment of a receiver or trustee for our property (See Section 1001); and

• the occurrence of any default or any other event under the first mortgage indenture, and the expiration of the applicable grace period, if any, specified in such first mortgage indenture, if the effect of such default or event is to accelerate, or to permit the acceleration of, the maturity of any amount due under the first mortgage indenture.

Remedies

Acceleration of Maturity. If an event of default occurs and is continuing, then the trustee or the holders of not less than 33% in principal amount of indenture bonds then outstanding may declare the principal amount (or if the indenture bonds are discount bonds, such portion of the principal amount as may be provided for such discount bonds pursuant to the terms of the indenture) of all of the indenture bonds then outstanding, together with premium, if any, and accrued interest, if any, thereon to be immediately due and payable. At any time after such declaration of acceleration of the indenture bonds then outstanding, but before the sale of any of the mortgaged property and before a judgment or decree for payment of money shall have been obtained by the trustee as provided in the indenture, the event or events of default giving rise to such declaration of acceleration will, without further act, be deemed to have been waived, and such declaration and its consequences will, without further act, be deemed to have been rescinded and annulled, if:

• we have paid or deposited with the trustee a sum sufficient to pay:

• all overdue interest, if any, on all indenture bonds then outstanding;

• the principal of and premium, if any, on any indenture bonds then outstanding which have become due otherwise than by such declaration of acceleration and interest thereon at the rate prescribed therefor in such indenture bonds; and

• all amounts due to the trustee as compensation and reimbursement as provided in the indenture; and

• any other event or events of default, other than the non-payment of the principal of indenture bonds that shall have become due solely by such declaration of acceleration, shall have been cured or waived as provided in the indenture. (See Section 1002)

Possession of Mortgaged Property

Under certain circumstances and to the extent permitted by law, if an event of default occurs and is continuing, the trustee has the power to take possession of, and to hold, operate and manage, the mortgaged property, or with or without entry, sell the mortgaged property. If the mortgaged property is sold, whether by the trustee or pursuant to judicial proceedings, the principal of the outstanding indenture bonds, if not previously due, will become immediately due and payable, together with premium, if any, and any accrued interest. (See Sections 1003, 1004 and 1005)

Right to Direct Proceedings

If an event of default occurs and is continuing, the holders of a majority in principal amount of the indenture bonds then outstanding will have the right to direct the time, method and place of conducting any proceedings for any remedy available to the trustee or exercising any trust or power conferred on the trustee, provided that such direction does not conflict with any rule of law or with the indenture, and could not involve the trustee in personal liability in circumstances where indemnity would not, in the trustee’s sole discretion, be adequate and the trustee may take any other action deemed proper by the trustee that is not inconsistent with such direction. (See Section 1016)

Limitation on Right to Institute Proceedings

No holder of any indenture bond will have any right to institute any proceeding, judicial or otherwise, with respect to the indenture or for the appointment of a receiver or for any other remedy thereunder unless

• such holder has previously given to the trustee written notice of a continuing event of default;

• the holders of not less than a majority in aggregate principal amount of the indenture bonds then outstanding have made written request to the trustee to institute proceedings in respect of such event of default and have offered the trustee reasonable indemnity against costs and liabilities to be incurred in complying with such request; and

• for sixty days after receipt of such notice, the trustee has failed to institute any such proceeding and no direction inconsistent with such request has been given to the trustee during such sixty-day period by the holders of a majority in aggregate principal amount of indenture bonds then outstanding.

Furthermore, no holder will be entitled to institute any such action if and to the extent that such action would disturb or prejudice the rights of other holders. (See Section 1011)

No Impairment of Right to Receive Payment

Notwithstanding that the right of a holder to institute a proceeding with respect to the indenture is subject to certain conditions precedent, each holder of an indenture bond has the absolute and unconditional right to receive payment of the principal of and premium, if any, and interest, if any, on such indenture bond when due and to institute suit for the enforcement of any such payment, and such rights may not be impaired without the consent of such holder. (See Section 1012)

Notice of Default

The trustee is required to give the holders notice of any default under the indenture to the extent required by the Trust Indenture Act, unless such default shall have been cured or waived, except that no such notice to holders of a default of the character described in the third bullet point under “Events of Default” may be given until at least 75 days after the occurrence thereof. (See Section 1102) The Trust Indenture Act currently permits the trustee to withhold notices of default (except for certain payment defaults) if the trustee in good faith determines the withholding of such notice to be in the interests of the holders.

Indemnification of Trustee

As a condition precedent to certain actions by the trustee in the enforcement of the lien of the indenture and institution of action on the indenture bonds, the trustee may require adequate indemnity against costs, expenses and liabilities to be incurred in connection therewith. (See Sections 1011 and 1101)

Remedies Limited by State Law

The laws of any jurisdiction where the mortgaged property is located may limit or deny the ability of the trustee or bondholders to enforce certain rights and remedies provided in the indenture in accordance with their terms.

Defeasance

Any indenture bonds, or any portion of the principal amount thereof, will be deemed to have been paid for purposes of the indenture, and, at our election, the entirety of our indebtedness in respect thereof will be deemed to have been satisfied and discharged, if there has been irrevocably deposited with the trustee or any paying agent (other than us), in trust:

• money (including funded cash not otherwise applied pursuant to the indenture) in an amount which will be sufficient; or

• in the case of a deposit made prior to the date on which principal is due, eligible obligations (as described below), which do not contain provisions permitting the redemption or other prepayment thereof at the option of the issuer thereof, the principal of and the interest on which when due, without any regard to reinvestment thereof, will provide monies which, together with the money, if any, deposited with or held by the trustee or such paying agent, will be sufficient; or

• a combination of options in the preceding bullet points which will be sufficient, to pay when due the principal of and premium, if any, and interest, if any, due and to become due on such indenture bonds or portions thereof. (See Section 901) For this purpose, eligible obligations include direct obligations of, or obligations unconditionally guaranteed by, the United States of America, entitled to the benefit of the full faith and credit thereof, and certificates, depositary receipts or other instruments that evidence a direct ownership interest in such obligations or in any specific interest or principal payments due in respect thereof.

Notwithstanding the foregoing, no indenture bond shall be deemed to have been paid as aforesaid unless we shall have delivered to the trustee either:

• an opinion of counsel in the United States reasonably acceptable to the trustee confirming that (i) we have received from, or there has been published by, the Internal Revenue Service a ruling or (ii) since the date of the indenture, there has been a change in the applicable federal income tax law, in either case to the effect that, and based thereon such opinion of counsel shall confirm that, the holders of the outstanding indenture bonds will not recognize income, gain or loss for federal income tax purposes as a result of such defeasance and will be subject to federal income tax on the same amounts, in the same manner and at the same times as would have been the case if such defeasance had not occurred; or

• an instrument wherein we, notwithstanding the satisfaction and discharge of our indebtedness in respect of indenture bonds, shall assume the obligation (which shall be absolute and unconditional) to irrevocably deposit with the trustee such additional sums of money, if any, or additional government obligations, if any, or any combination thereof, at such time or times, as shall be necessary, together with the money and/or government obligations theretofore so deposited, to pay when due the principal of and premium, if any, and interest due and to become due on such indenture bonds or portions thereof; provided, however, that such instrument may state that our obligation to make additional deposits as aforesaid shall be subject to the delivery to us by the trustee of a notice asserting the deficiency accompanied by an opinion of an independent public accountant of nationally recognized standing showing the calculation thereof; and

• an opinion of tax counsel in the United States reasonably acceptable to the trustee to the effect that the holders of the outstanding indenture bonds will not recognize income, gain or loss for federal income tax purposes as a result of such defeasance and will be subject to federal income tax on the same amounts, in the same manner and at the same times as would have been the case if such defeasance had not occurred.

Duties of the Trustee; Resignation; Removal

The trustee will have, and will be subject to, all the duties and responsibilities specified with respect to an indenture trustee under the Trust Indenture Act. Subject to such provisions, the trustee will be under no obligation to exercise any of the powers vested in it by the indenture at the request of any holder of indenture bonds, unless offered reasonable indemnity by such holder against the costs, expenses and liabilities which might be incurred thereby. The trustee will not be required to expend or risk its own funds or otherwise incur financial liability in the performance of its duties if the trustee reasonably believes that repayment or adequate indemnity is not reasonably assured to it.

The trustee may resign at any time by giving written notice thereof to us or may be removed at any time by the holders of a majority in principal amount of indenture bonds then outstanding delivered to the trustee and us. No resignation or removal of the trustee and no appointment of a successor trustee will become effective until the acceptance of appointment by a successor trustee in accordance with the requirements of the indenture. So long as no event of default or event which, after notice or lapse of time, or both, would become an event of default has occurred and is continuing, if we have delivered to the trustee a resolution of our board of directors appointing a successor trustee and such successor has accepted such appointment in accordance with the terms of the indenture, the trustee will be deemed to have resigned and the successor will be deemed to have been appointed as trustee in accordance with the indenture. (See Section 1110)

Evidence to be Furnished to the Trustee

Compliance with indenture provisions is evidenced by written statements of our officers or persons selected or paid by us. In certain cases, opinions of counsel and certification of an engineer, accountant, appraiser or other expert (who in some cases must be independent) must be furnished. In addition, the indenture requires that we give the trustee, not less often than annually, a brief statement as to our compliance with the conditions and covenants under the indenture.

DESCRIPTION OF OUR FIRST MORTGAGE BONDS

The following description of our First Mortgage Bonds is a summary and does not purport to be complete. It is subject to and qualified in its entirety by reference to our First Mortgage Indenture dated as of November 1, 1944 with The Bank of New York Mellon Trust Company, N.A. (successor to South Texas Commercial National Bank of Houston), as trustee, as amended and supplemented, which is incorporated by reference as an exhibit to the Annual Report on Form 10-K of which this Exhibit 4(ii) is a part. We encourage you to read the above referenced First Mortgage Indenture for additional information.

Security.

The First Mortgage Indenture constitutes a first mortgage lien on all of our present properties (except as stated below), subject to excepted encumbrances. There are excepted from the lien of the First Mortgage Indenture all of the following: cash and securities; equipment, materials or supplies acquired for consumption in the operation of our properties or for resale in the ordinary course of our business; timber, minerals, mineral rights and royalties; and accounts receivable, contracts, leases and operating agreements.

The First Mortgage Indenture contains provisions for subjecting certain after-acquired property to the lien thereof, subject to any preexisting liens and to certain limitations in the case of our consolidation or merger or the sale of substantially all of our assets.

The First Mortgage Indenture provides that the trustee thereunder will have a lien upon the mortgaged property, prior to the First Mortgage Bonds, for the payment of its reasonable compensation and expenses for indemnity against certain liabilities.

As of December 31, 2019, the aggregate principal amount of First Mortgage Bonds outstanding under the First Mortgage Indenture was approximately $102 million.

Events of Default. Each of the following events constitutes an event of default under the First Mortgage Indenture:

• failure to pay principal when due;

• failure to pay any interest installment, continued for 60 days;

• failure to pay any installment of any fund established under the First Mortgage Indenture for the purchase or redemption of any First Mortgage Bonds, continued for 60 days;

• failure to perform any covenant of the company, continued for 90 days after written notice; and

• certain events in bankruptcy, reorganization or insolvency.

EX-4.JJ

Exhibit 4(jj)

DESCRIPTION OF CENTERPOINT ENERGY RESOURCES CORP.’S SECURITIES

REGISTERED PURSUANT TO SECTION 12

OF THE SECURITIES EXCHANGE ACT OF 1934

As of December 31, 2019, CenterPoint Energy Resources Corp., a Delaware corporation, had one class of securities registered under Section 12 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”): (1) the 6.625% senior notes due 2037 (“Senior Notes” or “notes”). For purposes of this summary, the terms “we,” “our,” “ours,” and “us” refer only to CenterPoint Energy Resources Corp. and not to any of our subsidiaries.

DESCRIPTION OF THE SENIOR NOTES

Our debt securities are issued under an indenture, dated as of February 1, 1998, as supplemented, between us and The Bank of New York Mellon Trust Company, N.A. (successor to JPMorgan Chase Bank, National Association), as trustee (the “Indenture”), as amended and supplemented, in the case of the Senior Notes, by Supplemental Indenture No. 12, dated as of October 23, 2007, each of which are incorporated by reference as an exhibit to the Annual Report on Form 10-K of which this Exhibit 4(jj) is a part. As of December 31, 2019, $250,000,000 aggregate principal amount of the Notes were outstanding. We have summarized selected provisions of the Indenture and the Senior Notes below. This summary is not complete and is qualified in its entirety by reference to the Indenture and Supplemental Indenture No. 12. We encourage you to read the above referenced Indenture and Supplemental Indenture No. 12 for additional information.

Ranking of the Senior Notes. The Senior Notes:

• are general unsecured obligations,

• rank equally in right of payment with all of our other existing and future unsecured and unsubordinated indebtedness, and

• with respect to the assets and earnings of our subsidiaries, structurally rank below all of the liabilities of our subsidiaries.

Principal, Maturity and Interest. The Senior Notes mature on November 1, 2037. Interest on the Senior Notes accrues at the rate of 6.625% per annum. Interest on the Senior Notes:

• is payable semi-annually in arrears on each May 1 and November 1,

• is payable to the person in whose name the notes are registered at the close of business on the April 15 and October 15 immediately preceding the applicable interest payment date, which we refer to with respect to the notes as “regular record dates,”

• is computed on the basis of a 360-day year comprised of twelve 30-day months, and

• is payable on overdue interest to the extent permitted by law at the same rate as interest is payable on principal.

If any interest payment date, the maturity date or any redemption date falls on a day that is not a business day, the payment will be made on the next business day with the same force and effect as if made on the relevant interest payment date, maturity date or redemption date. Unless we default on a payment, no interest will accrue for the period from and after the applicable maturity date or redemption date.

Optional Redemption. We may redeem the Senior Notes, in whole or in part, at our option exercisable at any time and from time to time upon not less than 30 and not more than 60 days’ notice as provided in the indenture, on any date prior to their maturity at a redemption price equal to:

• 100% of the principal amount of the notes to be redeemed, plus

• accrued and unpaid interest thereon, if any, to, but excluding, the redemption date, plus

• the make-whole premium described below, if any.

The redemption price will never be less than 100% of the principal amount of the Senior Notes redeemed plus accrued and unpaid interest thereon, if any, to, but excluding, the redemption date. The amount of the make-whole premium with respect to any note to be redeemed will be equal to the excess, if any, of:

(1) the sum of the present values, calculated as of the redemption date, of:

• each interest payment that, but for such redemption, would have been payable on the note or portion thereof being redeemed on each interest payment date occurring after the redemption date (excluding any accrued and unpaid interest for the period prior to the redemption date), and

• the principal amount that, but for such redemption, would have been payable at the final maturity of the note or portion thereof being redeemed, over

(2) the principal amount of the note or portion thereof being redeemed.

The present values of interest and principal payments referred to in clause (1) above will be determined in accordance with generally accepted principles of financial analysis. These present values will be calculated by discounting the amount of each payment of interest or principal from the date that each such payment would have been payable, but for the redemption, to the redemption date at a discount rate equal to the comparable treasury yield (as defined below) plus 30 basis points.

The make-whole premium will be calculated by an independent investment banking institution of national standing appointed by us. If we fail to appoint an independent investment banking institution at least 45 days prior to the redemption date, or if the independent investment banking institution we appoint is unwilling or unable to calculate the make-whole premium, the calculation will be made by Citigroup Global Markets Inc., Morgan Stanley & Co. Incorporated or UBS Securities LLC. If Citigroup Global Markets Inc., Morgan Stanley & Co. Incorporated and UBS Securities LLC are unwilling or unable to make the calculation, we will appoint a different independent investment banking institution of national standing to make the calculation.

For purposes of determining the make-whole premium, “comparable treasury yield” means a rate of interest per annum equal to the weekly average yield to maturity of United States Treasury Securities that have a constant maturity that corresponds to the remaining term to maturity of the notes to be redeemed, calculated to the nearest 1/12th of a year. The comparable treasury yield will be determined as of the third business day immediately preceding the applicable redemption date.

The weekly average yields of United States Treasury Securities will be determined by reference to the most recent statistical release published by the Federal Reserve Bank of New York and designated “H.15(519) Selected Interest Rates” or any successor release. If this statistical release sets forth a weekly average yield for United States Treasury Securities having a constant maturity that is the same as the remaining term of the notes to be redeemed calculated as set forth above, then the comparable treasury yield will be equal to such weekly average yield. In all other cases, the comparable treasury yield will be calculated by interpolation on a straight-line basis, between the weekly average yields on the United States Treasury Securities that have a constant maturity closest to and greater than the remaining term of the notes to be redeemed and the United States Treasury Securities that have a constant maturity closest to and less than the remaining term of notes (in each case as set forth in the H.15 statistical release or any successor release). Any weekly average yields calculated by interpolation will be rounded to the nearest 1/100th of 1%, with any figure of 1/200th of 1% or above being rounded upward. If weekly average yields for United States Treasury Securities are not available in the H.15 statistical release or otherwise, then the comparable treasury yield will be calculated by interpolation of comparable rates selected by an independent investment banking institution selected in the manner described in the second preceding paragraph.

If we redeem less than all the Senior Notes, the trustee will select the Senior Notes for redemption on a pro rata basis, by lot or by such other method as the trustee in its sole discretion deems fair and appropriate. We will only redeem notes in multiples of $1,000 in original principal amount. If any note is to be redeemed in part only, the notice of redemption will state the portion of the principal amount to be redeemed. A new note in principal amount equal to the unredeemed portion of the original note will be issued upon the cancellation of the original note.

Sinking Fund. We are not obligated to make mandatory redemption or sinking fund payments with respect to the Senior Notes.

Restrictive Covenants. The Indenture does not limit the amount of indebtedness or other obligations that we may incur and does not contain provisions that would give holders of the notes the right to require us to repurchase their notes in the event of a change in control of us, or in the event we enter into one or more highly leveraged transactions, regardless of whether a rating decline results therefrom, or in the event we dispose of one or more of our business units, nor are any such events deemed to be events of default under the terms of the Indenture.

Limitations on Liens.  We will not, and we will not permit any subsidiary (as defined below) to, pledge, mortgage or hypothecate, or permit to exist, except in our favor or in favor of any subsidiary, any lien (as defined below) upon any principal property (as defined below) or any equity interest (as defined below) in any significant subsidiary (as defined below) owning any principal property, at any time owned by us or by a subsidiary, to secure any indebtedness (as defined below), unless effective provision is made whereby outstanding notes will be secured equally and ratably therewith (or prior thereto), and with any other indebtedness similarly entitled to be equally and ratably secured. This restriction will not apply to or prevent the creation or existence of:

• liens on any property held or used by us or a subsidiary in connection with the exploration for, development of or production of, oil, gas, natural gas (including liquefied gas and storage gas), other hydrocarbons, helium, coal, metals, minerals, steam, timber, geothermal or other natural resources or synthetic fuels, such properties to include, but not be limited to, our or a subsidiary’s interest in any mineral fee interests, oil, gas or other mineral leases, royalty, overriding royalty or net profits interests, production payments and other similar interests, wellhead production equipment, tanks, field gathering lines, leasehold or field separation and processing facilities, compression facilities and other similar personal property and fixtures,

• liens on oil, gas, natural gas (including liquefied gas and storage gas), other hydrocarbons, helium, coal, metals, minerals, steam, timber, geothermal or other natural resources or synthetic fuels produced or recovered from any property, an interest in which is owned or leased by us or a subsidiary,

• liens (or certain extensions, renewals or refundings thereof) upon any property acquired, constructed or improved before or after the date the notes are first issued, which liens were or are created at the later of the time of acquisition or commercial operation thereof, or within one year thereafter to secure all or a portion of the purchase price thereof or the cost of construction or improvement, or existing thereon at the date of acquisition, provided that every such mortgage, pledge, lien or encumbrance applies only to the property so acquired or constructed and fixed improvements thereon,

• liens upon any property of any entity acquired by any entity that is or becomes a subsidiary after the date the notes are first issued, each of which we refer to as an “acquired entity,” provided that every such mortgage, pledge, lien or encumbrance:

• will either:

• exist prior to the time the acquired entity becomes a subsidiary, or

• be created at the time the acquired entity becomes a subsidiary or within one year thereafter to secure payment of the acquisition price thereof, and

• will only apply to those properties owned by the acquired entity at the time it becomes a subsidiary or thereafter acquired by it from sources other than us or any other subsidiary,

• pledges of current assets, in the ordinary course of business, to secure current liabilities,

• deposits, including among others, good faith deposits in connection with tenders, leases of real estate or bids or contracts, or liens, including among others, liens reserved in leases and mechanics’ or materialmen’s liens, to secure certain duties or public or statutory obligations,

• liens upon any office, data processing or transportation equipment,

• liens created or assumed in connection with the issuance of debt securities, the interest on which is excludable from gross income of the holder of such security pursuant to the Internal Revenue Code, for the purpose of financing the acquisition or construction of property to be used by us or a subsidiary,

• pledges or assignments of accounts receivable or conditional sales contracts or chattel mortgages and evidence of indebtedness secured thereby, received in connection with the sale of goods or merchandise to customers, or

• certain liens for taxes, judgments and attachments.

Notwithstanding the foregoing, we or a subsidiary may issue, assume or guarantee indebtedness secured by a mortgage which would otherwise be subject to the foregoing restrictions in an aggregate amount which, together with all of our other indebtedness or indebtedness of a subsidiary secured by a mortgage (not including secured indebtedness permitted under the foregoing exceptions) and the value (as defined below) of all sale and leaseback transactions (as defined below) existing at such time (other than sale and leaseback transactions (i) which, if a lien, would have been permitted under the third or fourth bullet points above or (ii) as to which application of amounts have been made in accordance with “— Limitation on Sale and Leaseback Transactions” below), does not at the time such indebtedness is incurred exceed 5% of consolidated net tangible assets (as defined below), as shown on our most recent audited consolidated balance sheet preceding the date of determination. For purposes of this “Limitation on Liens” covenant, subsidiary does not include a project finance subsidiary (as defined below).

Limitation on Sale and Leaseback Transactions.  We will not, and we will not permit any subsidiary to, engage in a sale and leaseback transaction of any principal property unless the net proceeds of such sale are at least equal to the fair value of such principal property (as determined by our board of directors) and either:

• we or such subsidiary would be entitled under the indenture to incur indebtedness secured by a lien on the principal property to be leased, without equally and ratably securing the notes, pursuant to the exceptions provided in the third and fourth bullet points of the second sentence of “— Limitations on Liens” above, or

• within 120 days after the sale or transfer of the principal property, we apply an amount not less than the fair value of such property:

• to the payment or other retirement of our long-term indebtedness or long-term indebtedness of a subsidiary, in each case ranking senior to or on parity with the notes, or

• to the purchase at not more than the fair value of principal property (other than that involved in such sale and leaseback transaction).

For purposes of this “Limitation on Sale and Leaseback Transactions” covenant, subsidiary does not include a project finance subsidiary.

Defined Terms.

“Capital lease” means a lease that, in accordance with accounting principles generally accepted in the United States, would be recorded as a capital lease on the balance sheet of the lessee.

“Consolidated net tangible assets” means the total amount of our assets, including the assets of our subsidiaries, less, without duplication:

• total current liabilities (excluding indebtedness due within 12 months),

• all reserves for depreciation and other asset valuation reserves, but excluding reserves for deferred federal income taxes,

• all intangible assets such as goodwill, trademarks, trade names, patents and unamortized debt discount and expense carried as an asset, and

• all appropriate adjustments on account of minority interests of other persons holding common stock of any subsidiary, all as reflected in our most recent audited consolidated balance sheet preceding the date of such determination.

“Equity interests” means any capital stock, partnership, joint venture, member or limited liability or unlimited liability company interest, beneficial interest in a trust or similar entity or other equity interest or investment of whatever nature.

“Indebtedness,” as applied to us or any subsidiary, means bonds, debentures, notes and other instruments or arrangements representing obligations created or assumed by us or any such subsidiary, including any and all:

• obligations for money borrowed, other than unamortized debt discount or premium,

• obligations evidenced by a note or similar instrument given in connection with the acquisition of any business, properties or assets of any kind,

• obligations as lessee under a capital lease, and

• amendments, renewals, extensions, modifications and refundings of any such indebtedness or obligation listed in the three immediately preceding bullet points.

All indebtedness secured by a lien upon property owned by us or any subsidiary and upon which indebtedness we or any such subsidiary customarily pays interest, although we or any such subsidiary has not assumed or become liable for the payment of such indebtedness, is also deemed to be indebtedness of us or any such subsidiary. All indebtedness for borrowed money incurred by other persons which is directly guaranteed as to payment of principal by us or any subsidiary will for all purposes of the indenture be deemed to be indebtedness of us or any such subsidiary, but no other contingent obligation of us or any such subsidiary in respect of indebtedness incurred by other persons shall be deemed indebtedness of us or any such subsidiary.

“Lien” means any mortgage, deed of trust, pledge, hypothecation, assignment, deposit arrangement, charge, security interest, encumbrance or lien of any kind whatsoever (including any capital lease).

“Non-recourse debt” means (i) any indebtedness for borrowed money incurred by any project finance subsidiary to finance the acquisition, improvement, installation, design, engineering, construction, development, completion, maintenance or operation of, or otherwise to pay costs and expenses relating to or providing financing for, any project, which indebtedness for borrowed money does not provide for recourse against us or any of our subsidiaries (other than a project finance subsidiary and such recourse as exists under a performance guaranty) or any property or asset of us or any of our subsidiaries (other than equity interests in, or the property or assets of, a project finance subsidiary and such recourse as exists under a performance guaranty) and (ii) any refinancing of such indebtedness for borrowed money that does not increase the outstanding principal amount thereof (other than to pay costs incurred in connection therewith and the capitalization of any interest or fees) at the time of the refinancing or increase the property subject to any lien securing such indebtedness for borrowed money or otherwise add additional security or support for such indebtedness for borrowed money.

“Performance guaranty” means any guaranty issued in connection with any non-recourse debt that (i) if secured, is secured only by assets of or equity interests in a project finance subsidiary, and (ii) guarantees to the provider of such non-recourse debt or any other person (a) performance of the improvement, installation, design, engineering, construction, acquisition, development, completion, maintenance or operation of, or otherwise affects any such act in respect of, all or any portion of the project that is financed by such non-recourse debt, (b) completion of the minimum agreed equity or other contributions or support to the relevant project finance subsidiary, or (c) performance by a project finance subsidiary of obligations to persons other than the provider of such non-recourse debt.

“Principal property” means any natural gas distribution property, natural gas pipeline or gas processing plant located in the United States, except any such property that in the opinion of our board of directors is not of material importance to the total business conducted by us and our consolidated subsidiaries. “Principal property” shall not include any oil or gas property or the production or proceeds of production from an oil or gas producing property or the production or any proceeds of production of gas processing plants or oil or gas or petroleum products in any pipeline or storage field.

“Project finance subsidiary” and “project finance subsidiaries” means any of our subsidiaries designated by us whose principal purpose is to incur non-recourse debt and/or construct, lease, own or operate the assets financed thereby, or to become a direct or indirect partner, member or other equity participant or owner in a person created for such purpose, and substantially all the assets of which subsidiary or person are limited to (x) those assets being financed (or to be financed), or the operation of which is being financed (or to be financed), in whole or in part by non-recourse debt, or (y) equity interests in, or indebtedness or other obligations of, one or more other such subsidiaries or persons, or (z) indebtedness or other obligations of us or our subsidiaries or other persons. At the time of designation of any project finance subsidiary, the sum of the net book value of the assets of such subsidiary and the net book value of the assets of all other project finance subsidiaries then existing shall not in the aggregate exceed 10 percent of the consolidated net tangible assets.

“Sale and leaseback transaction” means any arrangement entered into by us or any subsidiary with any person providing for the leasing to us or any subsidiary of any principal property (except for temporary leases for a term, including any renewal thereof, of not more than three years and except for leases between us and a subsidiary or between subsidiaries), which principal property has been or is to be sold or transferred by us or such subsidiary to such person.

“Significant subsidiary” means any subsidiary of ours, other than a project finance subsidiary, that is a “significant subsidiary” as defined in Rule 1-02 of Regulation S-X under the Securities Act of 1933 and the Securities Exchange Act of 1934, as such regulation is in effect on the date of issuance of the notes.

“Subsidiary” of any entity means any corporation, partnership, joint venture, limited liability company, trust or estate of which (or in which) more than 50% of (i) the issued and outstanding capital stock having ordinary voting power to elect a majority of the board of directors of such corporation (irrespective of whether at the time capital stock of any other class or classes of such corporation shall or might have voting power upon the occurrence of any contingency), (ii) the interest in the capital or profits of such limited liability company, partnership, joint venture or other entity or (iii) the beneficial interest in such trust or estate is at the time directly or indirectly owned or controlled by such entity, by such entity and one or more of its other subsidiaries or by one or more of such entity’s other subsidiaries.

“Value” means, with respect to a sale and leaseback transaction, as of any particular time, the amount equal to the greater of (1) the net proceeds from the sale or transfer of the property leased pursuant to such sale and leaseback transaction or (2) the fair value, in the opinion of our board of directors, of such property at the time of entering into such sale and leaseback transaction, in either case divided first by the number of full years of the term of the lease and then multiplied by the number of full years of such term remaining at the time of determination, without regard to any renewal or extension options contained in the lease.

Payment and Paying Agent. We have designated the trustee as the sole paying agent for the Senior Notes.

Events of Default. Each of the following is an event of default under the indenture with respect to the Senior Notes; provided, however, that the event of default described in the fourth bullet point below will terminate pursuant to the termination provision of the indenture and will no longer be applicable to the notes on and after the termination date referred to under “Restrictive Covenants” above:

• our failure to pay principal or premium, if any, on the notes when due,

• our failure to pay any interest on the notes for 30 days,

• our failure to perform, or our breach in any material respect of, any other covenant or warranty in the indenture, other than a covenant or warranty included in the indenture solely for the benefit of another series of our debt securities issued under the indenture, for 90 days after either the trustee or holders of at least 25% in principal amount of the outstanding notes of that series have given us written notice of the breach in the manner required by the indenture,

• the default by us or any subsidiary, other than a project finance subsidiary, of ours in the payment, when due, after the expiration of any applicable grace period, of principal of indebtedness for money borrowed, other than non-recourse debt, in the aggregate principal amount then outstanding of $50 million or more, or acceleration of any indebtedness for money borrowed in such aggregate principal amount so that it becomes due and payable prior to the date on which it would otherwise have become due and payable and such acceleration is not rescinded or such default is not cured within 30 days after notice to us in accordance with the indenture, and

• specified events involving bankruptcy, insolvency or reorganization,

provided, however, that no event described in the third, fourth or fifth bullet points above will be an event of default until an officer of the trustee, assigned to and working in the trustee’s corporate trust department, has actual knowledge of the event or until the trustee receives written notice of the event at its corporate trust office, and the notice refers to the notes generally, us or the indenture. (Section 501)

If an event of default occurs and is continuing with respect to the notes, either the trustee or the holders of at least 25% in principal amount of the outstanding notes may declare the principal amount of the notes due and immediately payable. To declare the principal amount of the notes due and immediately payable, the trustee or the holders must deliver a notice that satisfies the requirements of the indenture. Upon a declaration by the trustee or the holders, we will be obligated to pay the principal amount of the notes.

This right does not apply if an event of default described in the fifth bullet point above occurs. If one of the events of default described in the fifth bullet point above occurs and is continuing, the notes then outstanding under the indenture shall be due and payable immediately.

After any declaration of acceleration of the notes, but before a judgment or decree for payment, the holders of a majority in principal amount of the outstanding notes may, under certain circumstances, rescind and annul the declaration of acceleration if all events of default, other than the non-payment of principal, have been cured or waived as provided in the indenture. (Section 502) 

If an event of default occurs and is continuing, the trustee will generally have no obligation to exercise any of its rights or powers under the indenture at the request or direction of any of the holders, unless the holders offer reasonable indemnity to the trustee. (Section 603) The holders of a majority in principal amount of the outstanding notes will generally have the right to direct the time, method and place of conducting any proceeding for any remedy available to the trustee or exercising any trust or power conferred on the trustee for the notes, provided that:

• the direction is not in conflict with any law or the indenture,

• the trustee may take any other action it deems proper which is not inconsistent with the direction, and

• the trustee will generally have the right to decline to follow the direction if an officer of the trustee determines, in good faith, that the proceeding would involve the trustee in personal liability or would otherwise be contrary to applicable law. (Section 512)

A holder of a note may only pursue a remedy under the indenture if:

• the holder has previously given the trustee written notice of a continuing event of default for the notes,

• holders of at least 25% in principal amount of the outstanding notes have made a written request to the trustee to pursue that remedy,

• the holders have offered reasonable indemnity to the trustee,

• the trustee fails to pursue that remedy within 60 days after receipt of the notice, request and offer of indemnity, and

• during that 60-day period, the holders of a majority in principal amount of the notes do not give the trustee a direction inconsistent with the request. (Section 507)

However, these limitations do not apply to a suit by a holder of a note demanding payment of the principal, premium, if any, or interest on a note on or after the date the payment is due. (Section 508)

We will be required to furnish to the trustee annually a statement by some of our officers regarding our performance or observance of any of the terms of the indenture and specifying all of our known defaults, if any. (Section 1004)

Defeasance.If we deposit with the trustee funds or government securities sufficient to make payments on the notes on the dates those payments are due and payable, then, at our option, either of the following will occur:

• we will be discharged from our obligations with respect to the notes (“legal defeasance”), or

• we will no longer have any obligation to comply with the restrictive covenants under the indenture, and the related events of default in the third and fourth bullet points under “— Events of Default” above and the restrictions described under “— Consolidation, Merger and Sale of Assets” below will no longer apply to us, but some of our other obligations under the indenture and the notes, including our obligation to make payments on those notes, will survive.

If we defease the notes, the holders of the notes will not be entitled to the benefits of the indenture, except for our obligations to:

• register the transfer or exchange of the notes,

• replace mutilated, destroyed, lost or stolen notes, and

• maintain paying agencies and hold moneys for payment in trust.

We will be required to deliver to the trustee an opinion of counsel that the deposit and related defeasance would not cause the holders of the notes to recognize gain or loss for federal income tax purposes and that the holders would be subject to federal income tax on the same amounts, in the same manner and at the same times as would have been the case if the deposit and related defeasance had not occurred. If we elect legal defeasance, that opinion of counsel must be based upon a ruling from the United States Internal Revenue Service or a change in law to that effect. (Sections 1401, 1402, 1403 and 1404).

Consolidation, Merger and Sale of Assets

Under the indenture, we may not consolidate with or merge into, or convey, transfer or lease our properties and assets substantially as an entirety, to any person, referred to as a “successor person,” and we may not permit any person to consolidate with or merge into, or convey, transfer or lease its properties and assets substantially as an entirety to us, unless:

• the successor person is a corporation, partnership, trust or other entity organized and validly existing under the laws of the United States of America or any state thereof or the District of Columbia,

• the successor person expressly assumes our obligations with respect to the debt securities and the indenture,

• immediately after giving effect to the transaction, no event of default, and no event which, after notice or lapse of time or both, would become an event of default, would occur and be continuing, and

• we have delivered to the trustee the certificates and opinions required under the indenture. (Section 801)

As used in the indenture, the term “corporation” means a corporation, association, company, joint-stock company or business trust.

Exchange and Transfer of the Senior Notes. The notes were issued in registered form, without coupons, in denominations of integral multiples of $1,000. Holders may present notes for exchange or for registration of transfer at the office of the security registrar or at the office of any transfer agent we designate for that purpose. The security registrar or designated transfer agent will exchange or transfer the notes if it is satisfied with the documents of title and identity of the person making the request. We will not charge a service charge for any exchange or registration of transfer of notes. However, we may require payment of a sum sufficient to cover any tax or other governmental charge payable for the exchange or registration of transfer. The trustee will serve as the security registrar. (Section 305) At any time we may:

• designate additional transfer agents,

• rescind the designation of any transfer agent, or

• approve a change in the office of any transfer agent.

However, we are required to maintain a transfer agent in each place of payment for the Senior Notes at all times. (Sections 305 and 1002)

In the event we elect to redeem the Senior Notes, neither we nor the trustee will be required to register the transfer or exchange of the Senior Notes:

• during the period beginning at the opening of business 15 days before the day we mail the notice of redemption for such notes and ending at the close of business on the day the notice is mailed, or

• if we have selected such notes for redemption, in whole or in part, except for the unredeemed portion of such notes. (Section 305)

Regarding the Trustee. The Bank of New York Mellon Trust Company, N.A., successor to JPMorgan Chase Bank, National Association, is the trustee, security registrar and paying agent under the Indenture for the Senior Notes. Our affiliates maintain brokerage relationships and a rabbi trust with the trustee and its affiliates.

Book-Entry Delivery and Settlement. The Senior Notes were issued in the form of one or more permanent global notes in definitive, fully registered, book-entry form. The global notes were either deposited with or on behalf of The Depository Trust Company and registered in the name of Cede & Co., as nominee of DTC, or remained in the custody of the trustee in accordance with the FAST Balance Certificate Agreement between DTC and the trustee. Beneficial interests in the global notes are represented through book-entry accounts of financial institutions acting on behalf of beneficial owners as direct and indirect participants in DTC. Investors may hold interests in the global notes through DTC either directly if they are participants in DTC or indirectly through organizations that are participants in DTC. DTC has advised us as follows:

• DTC is a limited-purpose trust company organized under the New York Banking Law, a “banking organization” within the meaning of the New York Banking Law, a member of the Federal Reserve System, a “clearing corporation” within the meaning of the New York Uniform Commercial Code and a “clearing agency” registered under Section 17A of the Securities Exchange Act of 1934.

• DTC holds securities that its participants deposit with DTC and facilitates the settlement among participants of securities transactions, such as transfers and pledges, in deposited securities through electronic computerized book-entry changes in participants’ accounts, thereby eliminating the need for physical movement of securities certificates.

• Direct participants include securities brokers and dealers, banks, trust companies, clearing corporations and other organizations.

• DTC is owned by a number of its direct participants and by The New York Stock Exchange, Inc., the American Stock Exchange LLC and the Financial Industry Regulatory Authority, Inc.

• Access to the DTC system is also available to others such as securities brokers and dealers, banks and trust companies that clear through or maintain a custodial relationship with a direct participant, either directly or indirectly.

• The rules applicable to DTC and its direct and indirect participants are on file with the SEC.

We have provided the description of the operations and procedures of DTC herein solely as a matter of convenience. These operations and procedures are solely within the control of DTC and are subject to change by it from time to time. Neither we nor the underwriters or the trustee takes any responsibility for these operations or procedures, and you are urged to contact DTC or its participants directly to discuss these matters.

We expect that under procedures established by DTC:

• upon deposit of the global notes with DTC or its custodian, DTC will credit on its internal system the accounts of direct participants designated by the underwriters with portions of the principal amounts of the global notes; and

• ownership of the notes will be shown on, and the transfer of ownership thereof will be effected only through, records maintained by DTC or its nominee, with respect to interests of direct participants, and the records of direct and indirect participants, with respect to interests of persons other than participants.

The laws of some jurisdictions may require that purchasers of securities take physical delivery of those securities in definitive form. Accordingly, the ability to transfer interests in the notes represented by a global note to those persons may be limited. In addition, because DTC can act only on behalf of its participants, who in turn act on behalf of persons who hold interests through participants, the ability of a person having an interest in notes represented by a global note to pledge or transfer those interests to persons or entities that do not participate in DTC’s system, or otherwise to take actions in respect of such interest, may be affected by the lack of a physical definitive security in respect of such interest.

So long as DTC or its nominee is the registered owner of a global note, DTC or that nominee will be considered the sole owner or holder of the notes represented by that global note for all purposes under the indenture and under the notes. Except as provided below, owners of beneficial interests in a global note will not be entitled to have notes represented by that global note registered in their names, will not receive or be entitled to receive physical delivery of certificated notes and will not be considered the owners or holders thereof under the indenture or under the notes for any purpose, including with respect to the giving of any direction, instruction or approval to the trustee. Accordingly, each holder owning a beneficial interest in a global note must rely on the procedures of DTC and, if that holder is not a direct or indirect participant, on the procedures of the participant through which that holder owns its interest, to exercise any rights of a holder of notes under the indenture or the global note.

Neither we nor the trustee will have any responsibility or liability for any aspect of the records relating to or payments made on account of notes by DTC, or for maintaining, supervising or reviewing any records of DTC relating to the notes.

Payments on the notes represented by the global notes will be made to DTC or its nominee, as the case may be, as the registered owner thereof. We expect that DTC or its nominee, upon receipt of any payment on the notes represented by a global note, will credit participants’ accounts with payments in amounts proportionate to their respective beneficial interests in the global note as shown in the records of DTC or its nominee. We also expect that payments by participants to owners of beneficial interests in the global note held through such participants will be governed by standing instructions and customary practice as is now the case with securities held for the accounts of customers registered in the names of nominees for such customers. The participants will be responsible for those payments.

Certificated Notes. Certificated notes will be issued to each person that DTC identifies as the beneficial owner of the notes represented by the global notes, upon surrender by DTC of the global notes, if (i) DTC or any successor depositary (the “depositary”) notifies us that it is no longer willing or able to act as a depositary for the global notes or DTC ceases to be registered as a clearing agency under the Securities Exchange Act of 1934 and a successor depositary is not appointed within 90 days of such notice or cessation, (ii) we, at our option and subject to DTC procedures, notify the trustee in writing that we elect to cause the issuance of notes in definitive form under the indenture or (iii) upon the occurrence of certain other events as provided pursuant to the indenture.

EX-10.(H)

Exhibit 10(h)

CenterPoint Energy, Inc.

Summary of Certain Compensation Arrangements

of the Executive Chairman of the Board

The following is a summary of certain compensation arrangements payable to Milton Carroll, the Executive Chairman of the Board of Directors (the “Board”) of CenterPoint Energy, Inc. (the “Company”):

• Mr. Carroll’s annual base salary is increased from $760,000 to $820,000 effective as of April 1, 2020 and continuing thereafter until the termination of Mr. Carroll’s service as Executive Chairman of the Board or as otherwise modified by the Board;

• Mr. Carroll will receive a 2019 bonus of $500,000; and

• No changes were made to Mr. Carroll’s long-term incentive compensation target of 325% of base salary.

Mr. Carroll was not granted any additional awards of restricted stock units in 2020, other than in connection with his long-term incentive award noted above.

EX-10.N2

Exhibit 10(n)(2)

CENTERPOINT ENERGY, INC.

STOCK PLAN FOR OUTSIDE DIRECTORS

(As Amended and Restated Effective April 26, 2018)

First Amendment

WHEREAS, CenterPoint Energy, Inc., a Texas corporation (the “Company”), established and maintains the CenterPoint Energy, Inc. Stock Plan for Outside Directors, as amended and restated effective April 26, 2018 (the “Plan”); and

WHEREAS, the Board of Directors of the Company has reserved the right under Section 6.1 to amend the Plan, subject to prior approval by the Company’s shareholders to the extent such approval is determined to be required by applicable legal and/or stock exchange requirements; and

WHEREAS, the Company desires to amend the Plan to increase the number of shares of common stock of the Company (“Common Stock”) available for issuance and delivery under the Plan by 350,000 shares;

WHEREAS, an increase in the number of shares of Common Stock available under the Plan by 350,000 shares is subject to approval by the shareholders of the Company in accordance with applicable New York Stock Exchange regulations;

NOW, THEREFORE, in consideration of the foregoing, subject to approval by the shareholders of the Company at the April 24, 2020 Annual Meeting of Shareholders of the Company, effective as of April 24, 2020, (i) the number of shares of Common Stock available for issuance and delivery under the Plan is hereby increased by 350,000 shares and (ii) the first sentence of Section 3.1 of the Plan is amended to read as follows:

“The aggregate number of shares of Common Stock which may be issued or delivered under this Plan shall not exceed 1,050,000 shares, subject to adjustment as hereinafter provided.”

IN WITNESS WHEREOF, the Company has caused these presents to be executed by its duly authorized officer in a number of copies, all of which shall constitute one and the same instrument, which may be sufficiently evidenced by any executed copy hereof, on this 19th day of February, 2020, and effective as of April 24, 2020.

[Signature Page Follows]

	CENTERPOINT ENERGY, INC.
By	/s/ John W. Somerhalder II
	John W. Somerhalder II
	Interim President and Chief Executive Officer

ATTEST:

 /s/ Vincent A. Mercaldi

Vincent A. Mercaldi

Corporate Secretary

EX-10.Q2

Exhibit 10(q)(2)

CENTERPOINT ENERGY, INC.

2009 LONG TERM INCENTIVE PLAN

PERFORMANCE AWARD AGREEMENT
FOR OFFICERS AND DIRECTOR EMPLOYEESJANUARY 1, 20XX – DECEMBER 31, 20XX PERFORMANCE CYCLE

Pursuant to this Performance Award Agreement (the “Award Agreement”), CENTERPOINT ENERGY, INC. (the “Company”) hereby grants to <first_name> <last_name>, an employee of the Company, this Performance Award (the “Award”) covering the target number of shares, <shares_awarded>, of Common Stock (the “Target Shares”) pursuant to the CENTERPOINT ENERGY, INC. 2009 LONG TERM INCENTIVE PLAN (the “Plan”). The number of Target Shares shall be subject to adjustment as provided in Section 14 of the Plan, conditioned upon the Company’s achievement of the Performance Goals over the course of the 20XX – 20XX Performance Cycle, and subject to the following terms and conditions:

1.Relationship to the Plan. The Award is subject to all of the terms, conditions and provisions of the Plan in effect on the date hereof and administrative interpretations thereunder, if any, adopted by the Committee. To the extent that any provision of this Award Agreement conflicts with the express terms of the Plan, it is hereby acknowledged and agreed that the terms of the Plan shall control and, if necessary, the applicable provisions of this Award Agreement shall be hereby deemed amended so as to carry out the purpose and intent of the Plan. References to the Participant herein also include the heirs or other legal representatives of the Participant.

2.Definitions. Except as defined herein, capitalized terms shall have the same meanings ascribed to them under the Plan. For purposes of this Award Agreement:

“Achievement Percentage” means the percentage of achievement determined by the Committee after the end of the Performance Cycle in accordance with Section 4 that reflects the extent to which the Company achieved the Performance Goals during the Performance Cycle.

“Cause” means the Participant's (a) gross negligence in the performance of his or her duties, (b) intentional and continued failure to perform his or her duties, (c) intentional engagement in conduct which is materially injurious to the Company or its Subsidiaries (monetarily or otherwise) or (d) conviction of a felony or a misdemeanor involving moral turpitude. For this purpose, an act or failure to act on the part of the Participant will be deemed “intentional” only if done or omitted to be done by the Participant not in good faith and without reasonable belief that his or her action or omission was in the best interest of the Company, and no act or failure to act on the part of the Participant will be deemed “intentional” if it was due primarily to an error in judgment or negligence.

“Change in Control Closing Date” means the date a Change in Control is consummated during the Performance Cycle.

“Change in Control Payment Date” means the following:

(a)If the Change in Control is a Section 409A Change in Control, then the Change in Control Payment Date shall be not later than the 70th day after the Change in Control Closing Date; and

(b)If the Change in Control is a Non-Section 409A Change in Control, then the Change in Control Payment Date shall be a date following the last day of the Performance Cycle but no later than March 15th of the calendar year following the calendar year in which occurs the last day of the Performance Cycle; provided, however, in the case of the Participant’s death or Separation from Service after the Change in Control but prior to such date, all shares not previously paid shall be paid not later than the 70th day after the Participant’s Separation from Service date except as otherwise provided in Section 7(c).

“Covered Termination” means a Separation from Service that occurs within two years after the date upon which a Change in Control occurs and that does not result from any of the following:

(a)death;

(b)Disability;

(c)involuntary termination for Cause; or

(d)resignation by the Participant, unless such resignation is for Good Reason.

“Disability” means thatthe Participant is eligible for and in receipt of benefits under the Company’s long-term disability plan.

“Employment” means employment with the Company or any of its Subsidiaries.

“Good Reason” means any one or more of the following events:

(a)a failure to maintain the Participant in the position, or a substantially equivalent position, with the Company and/or a Subsidiary, as the case may be, which the Participant held immediately prior to the Change in Control;

(b)a significant adverse change in the authorities, powers, functions, responsibilities, duties, or reporting structure which the Participant held immediately prior to the Change in Control;

(c)a significant reduction in the Participant’s annual base salary as in effect immediately prior to the date on which a Change in Control occurs;

(d)a significant reduction in the Participant’s qualified retirement benefits, nonqualified benefits and welfare benefits provided to the Participant immediately prior to the date on which a Change in Control occurs; provided, however, that a contemporaneous diminution of or reduction in qualified retirement benefits and/or welfare benefits which is of general application and which uniformly and contemporaneously reduces or diminishes the benefits of all covered employees shall be ignored and not be considered a reduction in remuneration for purposes of this paragraph (d);

(e)a significant reduction in the Participant’s overall compensation opportunities (as contrasted with overall compensation actually paid or awarded) under a short-term incentive plan, a long-term incentive plan or other equity plan (or in such substitute or alternative plans) from that provided to the Participant immediately prior to the date on which a Change in Control occurs;

(f)a change in the location of the Participant’s principal place of employment with the Company by more than 50 miles from the location where the Participant was principally employed immediately prior to the date on which a Change in Control occurs; or

(g)a failure by the Company to provide directors and officers liability insurance covering the Participant comparable to that provided to the Participant immediately prior to the date on which a Change in Control occurs;

provided, however, that no later than 30 days after learning of the action (or inaction) described herein as the basis for a termination of employment for Good Reason, the Participant shall advise the Company in writing that the action (or inaction) constitutes grounds for a termination of his or her Employment for Good Reason, in which event the Company shall have 30 days (the “Cure Period”) to correct such action (or inaction). If such action (or inaction) is not corrected prior to the end of the Cure Period, then the Participant may terminate his or her Employment with the Company for Good Reason within the 30-day period following the end of the Cure Period by giving written notice to the Company. If such action (or inaction) is corrected before the end of the Cure Period, then the Participant shall not be entitled to terminate his or her Employment for Good Reason as a result of such action (or inaction).

“Non-Section 409A Change in Control” means a Change in Control that is not a Section 409A Change in Control.

“Performance Cycle” means the period beginning on January 1, 20XX and ending on December 31, 20XX.

“Performance Goal” means the standards established by the Committee for the Performance Cycle to determine in whole or in part the number of Vested Shares pursuant to Section 4, which are specified in a separate document provided with this Award Agreement and made a part hereof for all purposes.

“Retirement” means a Separation from Service (a) on or after the attainment of age 55 and (b) with at least five years of Employment; provided, however, that such Separation from Service is not by the Company for Cause or due to Disability.

“Sale of a Subsidiary” means, with respect to the Subsidiary for which the Participant is performing services at the time of the applicable event, the occurrence of any of the following events:

(a)A change in the ownership of such Subsidiary, as determined in accordance with Treasury Regulation § 1.409A-3(i)(5)(v) or

(b)A change in the ownership of a substantial portion of such Subsidiary’s assets, as determined in accordance with Treasury Regulation § 1.409A-3(i)(5)(vii).

If the Subsidiary is not a corporation, the above referenced Treasury Regulations may be applied by analogy in accordance with guidance issued under Section 409A.

“Section 16 Officer” means a Participant who is an “officer” within the meaning of Section 16 of the Exchange Act as of the date notice of the Participant’s Retirement is provided in accordance with Section 5(b)(iv).

“Section 409A” means Code Section 409A and the Treasury regulations and guidance issued thereunder.

“Section 409A Change in Control” means a Change in Control that satisfies the requirements of a change in control for purposes of Code Section 409A(a)(2)(A)(v) and the Treasury regulations and guidance issued thereunder.

“Separation from Service” means a separation from service with the Company or any of its Subsidiaries within the meaning of Treasury Regulation § 1.409A-1(h) (or any successor regulation).

“Target Shares” means the actual number of shares originally granted to the Participant as specified in this Award Agreement.

“Vested Shares” means the shares of Common Stock actually distributable to the Participant following the Participant’s satisfaction of the vesting provisions of Section 5 and, if applicable, the determination by the Committee of the extent to which the Company has achieved the Performance Goals for the Performance Cycle pursuant to Section 4.

3.Establishment of Award Account. The grant of Target Shares pursuant to this Award Agreement shall be implemented by a credit to a bookkeeping account maintained by the Company evidencing the Participant’s unfunded and unsecured right to receive shares of Common Stock of the Company, which right shall be subject to the terms, conditions and restrictions set forth in the Plan and to the further terms, conditions and restrictions set forth in this Award Agreement. Except as otherwise provided in this Award Agreement, the Target Shares of Common Stock credited to the Participant’s bookkeeping account may not be sold, assigned, transferred, pledged or otherwise encumbered until the Participant has been registered as a holder of shares of Common Stock on the records of the Company as provided in Section 6 or 7 of this Award Agreement.

4.Award Opportunity.

(a)Except as otherwise provided in Section 5(b)(ii), Section 5(b)(iii) or Section 6, the Participant’s Vested Shares shall be the product of the number of Target Shares and the Achievement Percentage that is based upon the Committee’s determination of whether and to what extent the Performance Goals have been achieved during the Performance Cycle.

(b)No later than 60 days after the close of the Performance Cycle, the Committee shall determine the extent to which each Performance Goal has been achieved. If the Company has performed at or above the threshold level of achievement for a Performance Goal, the Achievement Percentage shall be between X% and X%. In no event shall the Achievement Percentage exceed X%. Upon completing its determination of the level at which the Performance Goals have been achieved, the Committee shall notify the Participant, in the form and manner as determined by the Committee, of the number of Vested Shares that will be issued to the Participant pursuant to Section 5.

5.Vesting of Shares.

(a)Unless earlier forfeited in accordance with Section 5(b)(i) or unless earlier vested in accordance with Section 5(b)(ii), Section 6(b), Section 6(c) or Section 6(d), the Participant’s right to receive shares pursuant to this Award Agreement, if any, shall vest on the last day of the Performance Cycle (with the number of shares, if any, based on the Committee’s determination that each Performance Goal has been met (as provided in Section 4)). As soon as administratively practicable, but in no event later than 70 days, after the close of the Performance Cycle, the Committee shall notify the Participant as required by Section 4 of the level at which the Performance Goals established for the Performance Cycle have been achieved.

(b)If the Participant’s Separation from Service date occurs prior to the close of the Performance Cycle and the occurrence of a vesting event described in Section 6(b), 6(c), or 6(d) (in connection with a Change in Control or a Sale of a Subsidiary), then the applicable of the following clauses shall apply with respect to the Target Shares subject to this Award Agreement:

(i)Forfeiture of Entire Award. If the Participant’s Employment is terminated, such that the Participant has a Separation from Service, by the Company or any of its Subsidiaries or by the Participant for any reason other than due to death, Disability or Retirement, then the Participant’s right to receive any Target Shares shall be forfeited in its entirety as of the date of such Separation from Service.

(ii)Death or Disability. If the Participant’s Employment is terminated due to death or Disability, the Participant’s right to receive the Target Shares shall vest on the date of such Separation from Service. The Participant’s right to receive any additional shares pursuant to this Award Agreement shall be forfeited at such time.

(iii)Retirement. If the Participant’s Employment is terminated due to Retirement, the Participant’s right to receive shares pursuant to this Award Agreement, if any, shall vest on the date the Committee determines that each Performance Goal has been met (as provided in Section 4) in a pro-rata amount determined by multiplying (1) the number of shares awarded to the Participantbased upon the Committee’s determination of achievement of Performance Goals as provided in Section 4, by (2) a fraction, the numerator of which is the number of days elapsed in the Performance Cycle as of the date of the Participant’s Separation from Service, and the denominator of which is the total number of days in the Performance Cycle.

(iv)Enhanced Retirement. If the Participant’s Employment is terminated due to Retirement and the requirements set forth under paragraph (1) or (2) below, as applicable, are satisfied, then in lieu of the rights and benefits set forth in Section 5(b)(iii), on the date the Committee determines that each Performance Goal has been met (as provided in Section 4), the Participant shall vest in the right to receive the total number of Vested Shares awarded to the Participantbased upon the Committee’s determination of achievement of Performance Goals as provided in Section 4.

(1)This paragraph (1) applies if the Participant is not a Section 16 Officer at the time of Retirement, and the requirements of this paragraph are satisfied if:

(A) the sum of the Participants age and years of Employment is 65 or greater;

(B) the Participant’s Retirement occurs on or after the first anniversary of the beginning of the Performance Cycle;

(C) the Participant provides to the Company a transition plan; and

(D) the Participant provides the Company at least six months’ written notice of the Participant’s Retirement.

(2)This paragraph (2) applies if the Participant is a Section 16 Officer at the time of Retirement, and the requirements of this paragraph are satisfied if: (x) the Participant satisfies (A), (B), and (C) under paragraph (1) above; (y) the Participant provides reasonable advance written notice (as determined by the Committee) of the Participant’s Retirement to the Chief Human Resources officer; and (z) the Committee approves providing the benefits set forth in this Section 5(b)(iv) above. Any such approval must occur prior to the Participant’s Separation from Service and is at the sole discretion of the Committee.

(c)In accordance with the provisions of this Section 5, the Vested Shares shall be distributed as provided in Section 7 hereof.

6.Change in Control.

(a)Assumption or Substitution. In the event of a Change in Control, the surviving, continuing, successor, or purchasing corporation or other business entity or parent thereof, as the case may be (the "Acquiror"), may, without the Participant’s consent, either assume or continue the Company’s rights and obligations under this Award Agreement or provide a substantially equivalent award in substitution for the shares subject to this Award.

(b)Vesting Upon a Change in Control. Notwithstanding anything herein to the contrary and without regard to the Performance Goals, if (i) there is a Change in Control during the Performance Cycle and prior to the Participant’s Separation from Service due to death or Disability and (ii) the Acquiror does not assume or continue this Award or provide a substantially equivalent award in substitution for this Award pursuant to Section 6(a), then upon the Change in Control Closing Date, the Participant’s right to receive the Target Shares shall vest. Notwithstanding the foregoing, in the event the Change in Control occurs after the Participant has had a Separation from Service due to Retirement, unless the requirements set forth in Section 5(b)(iv)(1), (2), (3), and (4) are satisfied, the Target Shares such Participant shall receive under this Section 6(b) shall be pro-rated based on the number of days that elapsed in the Performance Cycle as of the date of the Participant’s Separation from Service over the total number of days in the Performance Cycle.

(c)Vesting Upon a Covered Termination. Notwithstanding anything herein to the contrary and without regard to the Performance Goals, if the Participant experiences a Covered Termination during the Performance Cycle, then, upon the date of the Covered Termination, the Participant's right to receive the Target Shares shall vest.

(d)Vesting Upon the Sale of a Subsidiary. Notwithstanding anything herein to the contrary and without regard to the Performance Goals, if (i) a Sale of a Subsidiary with respect to the Participant occurs during the Performance Cycle and (ii) the Participant’s employment with the Company and all Subsidiaries (other than any entity that ceases to be a Subsidiary as a result of the Sale of a Subsidiary) ceases upon and in connection with such Sale of a Subsidiary, then upon such Sale of a Subsidiary, the Participant’s right to receive the Target Shares shall vest in the proportion of the number of days elapsed in the Performance Cycle as of the date of the Sale of a Subsidiary by the total number of days in the Performance Cycle. The Participant’s right to receive any additional shares pursuant to this Award Agreement shall be forfeited at such time.

(e)Distributions Upon a Change in Control or Sale of a Subsidiary.If the Participant is entitled to a benefit pursuant to Section 6(b), 6(c), or 6(d) hereof, then this Award shall be settled by the distribution to the Participant of:

i.shares of Common Stock equal to the Target Shares (or such pro-rated amount as set forth in Section 6(b) or 6(d), if applicable); plus

ii.Dividend Equivalents on such shares of Common Stock in the form of shares of Common Stock (rounded up to the nearest whole share) for the period commencing at the beginning of the Performance Cycle and ending on the date immediately preceding the date of the distribution.

In lieu of the foregoing distribution in shares, the Committee, in its sole discretion, may direct that such distribution be made to the Participant in a lump cash payment equal to:

(1)the product of (i) the Fair Market Value per share of Common Stock on the date immediately preceding the date of the distribution and (ii) the Target Shares (or such pro-rated amount as set forth in Section 6(b) or 6(d), if applicable); plus

(2)Dividend Equivalents on such shares of Common Stock for the period commencing at the beginning of the Performance Cycle and ending on the date immediately preceding the date of the distribution.

Such distribution, whether in the form of shares of Common Stock or, if directed by the Committee, in cash, shall satisfy the rights of the Participant and the obligations of the Company under this Award Agreement in full.

(f)Timing of Distribution.

(1)No Assumption or Substitution. If the Participant is entitled to a benefit pursuant to Section 6(b), distributions shall be made in accordance with Section 6(e) on the Change in Control Payment Date.

(2)Covered Termination. If the Participant is entitled to a benefit pursuant to Section 6(c) on account of a Covered Termination, distributions shall be made in accordance with Section 6(e) not later than the 70th day after the Participant’s Separation from Service date except as otherwise provided in Section 7(c).

(3)Sale of a Subsidiary. If the Participant is entitled to a benefit pursuant to Section 6(d), distributions shall be made in accordance with Section 6(e) not later than the 70th day after the date the Sale of a Subsidiary is consummated.

7.Distribution of Vested Shares.

(a)If the Participant’s right to receive shares pursuant to this Award Agreement has vested pursuant to Section 5(a) or Section 5(b)(iii) or (iv), a number of shares of Common Stock equal to the number of Vested Shares shall be distributed no later than March 15th of the calendar year following the calendar year in which occurs the last day of the Performance Cycle.

(b)If the Participant’s right to receive shares pursuant to this Award Agreement has vested pursuant to Section 5(b)(ii), a number of shares of Common Stock equal to the number of Vested Shares shall be distributed not later than the 70th day after the Participant’s Separation from Service date except as otherwise provided in Section 7(c).

(c)With respect to any benefits payable hereunder upon the Participant’s Separation from Service (other than a Separation from Service due to the Participant’s death), if as of the Participant’s Separation from Service date, the Participant is a “specified employee” (within the meaning of Section 409A(a)(2)(B)), then such benefits shall not be distributed until the date that is the earlier of (x) the second business day following the end of the six-month period commencing on the Participant's Separation from Service date or (y) the Participant's date of death, if death occurs during such six-month period.

(d)The Company shall have the right to withhold applicable taxes from any such distribution of Vested Shares or from other compensation payable to the Participant at the time of such vesting and distribution pursuant to Section 11 of the Plan (but subject to compliance with the requirements of Section 409A, if applicable).

(e)Upon distribution of the Vested Shares pursuant to this Section 7, the Participant shall also be entitled to receive Dividend Equivalents for the Vested Shares for the period after the commencement of the Performance Cycle but prior to the date the Vested Shares are delivered to the Participant (in accordance with the requirements of Section 409A, to the extent applicable).

8.Confidentiality. The Participant agrees that the terms of this Award Agreement are confidential and that any disclosure to anyone for any purpose whatsoever (save and except disclosure to financial institutions as part of a financial statement, financial, tax and legal advisors, or as required by law) by the Participant or his or her agents, representatives, heirs, children, spouse, employees or spokespersons shall be a breach of this Award Agreement and the Company may elect to revoke the grant made hereunder, seek damages, plus interest and reasonable attorneys’ fees, and take any other lawful actions to enforce this Award Agreement.

9.Participant Obligations.

(a)Confidentiality. The Participant acknowledges that in the course of his or her employment with the Company, the Company agrees to provide to the Participant Confidential Information regarding the Company and the Company’s business and has previously provided the Participant other such Confidential Information. In return for this and other consideration, provided under this Award Agreement, the Participant agrees that he or she will not, while employed by the Company and thereafter, disclose or make available to any other person or entity, or use for his own personal gain, any Confidential Information, except for such disclosures as required in the performance of his or her duties hereunder or as may otherwise be required by law or legal process (in which case the Participant shall notify the Company of such legal or judicial proceeding by a non-governmental party as soon as practicable following his receipt of notice of such a proceeding, and permit the Company to seek to protect its interests and information). Nothing in this Award Agreement, however, limits or precludes Participant from making a good faith voluntary report, charge, complaint, or claim to or providing truthful testimony and documents as required by law or under oath pursuant to a subpoena, court order, or request by the Equal Employment Opportunity Commission, the National Labor Relations Board, the Occupational Safety and Health Administration, the Securities and Exchange Commission or any other federal, state, or local government agency or commission (“Government Agencies”). Participant further understands that this Award Agreement does not limit Participant’s ability to communicate with any Government Agencies or otherwise participate in any investigation or proceeding that may be conducted by any Government Agency, including providing documents or other information to the Government Agency, without notice to the Company. For purposes of this Award Agreement, “Confidential Information” shall mean any and all information, data and knowledge that has been created, discovered, developed or otherwise become known to the Company or any of its affiliates or ventures or in which property rights have been assigned or otherwise conveyed to the Company or any of its affiliates or ventures, which information, data or knowledge has commercial value in the business in which the Company is engaged, except such information, data or knowledge as is or becomes known to the public without violation of the terms of this Award Agreement. By way of illustration, but not limitation, Confidential Information includes business trade secrets, secrets concerning the Company’s plans and strategies, nonpublic information concerning material market opportunities, technical trade secrets, processes, formulas, know-how, improvements, discoveries, developments, designs, inventions, techniques, marketing plans, manuals, records of research, reports, memoranda, computer software, strategies, forecasts, new products, unpublished financial information, projections, licenses, prices, costs, and employee, customer and supplier lists or parts thereof.

(b)Return of Property. The Participant agrees that at the time of his or her Separation from Service, he or she will deliver to the Company (and will not keep in his or her possession, recreate or deliver to anyone else) all Confidential Information as well as all other devices, records, data, notes, reports, proposals, lists, correspondence, specifications, drawings, blueprints, sketches, materials, equipment, customer or client lists or information, or any other documents or property (including all reproductions of the aforementioned items) belonging to the Company or any of its affiliates or ventures, regardless of whether such items were prepared by the Participant.

(c)Non-Solicitation and Non-Competition.

(1)Non-Solicitation. For consideration provided under this Award Agreement, including, but not limited to the Company’s agreement to provide the Participant with Confidential Information (as defined in Section 9(a)) regarding the Company and the Company’s business, the Participant agrees that, while employed by the Company and for one year following his or her Separation from Service, he or she shall not, without the prior written consent of the Company, directly or indirectly, (i) hire or induce, entice or solicit (or attempt to induce, entice or solicit) any employee of the Company or any of its affiliates or ventures to leave the employment of the Company or any of its affiliates or ventures or (ii) solicit or attempt to solicit the business of any customer or acquisition prospect of the Company or any of its affiliates or ventures with whom the Participant had any actual contact while employed at the Company.

(2)Non-Competition. For consideration provided under this Award Agreement, including, but not limited to the Company’s agreement to provide the Participant with Confidential Information regarding the Company and the Company’s business, the Participant agrees that while employed by the Company and for one year following a Separation from Service he or she will not, without the prior written consent of the Company, acting alone or in conjunction with others, either directly or indirectly, engage in any business that is in competition with the Company or accept employment with or render services to such a business as an officer, agent, employee, independent contractor or consultant, or otherwise engage in activities that are in competition with the Company.

(3)Restricted Area. The restrictions contained in this Section 9(c) are limited to a 50-mile radius around any geographical area in which the Company engages (or has definite plans to engage) in operations or the marketing of its products or services at the time of the Participant’s Separation from Service.

(d)Restrictions Reasonable. The Participant acknowledges that the restrictive covenants under this Section 9, for which the Participant received valuable consideration from the Company as provided in this Award Agreement, including, but not limited to the Company’s agreement to provide the Participant with Confidential Information regarding the Company and the Company’s business are ancillary to otherwise enforceable provisions of this Award Agreement that the consideration provided by the Company gives rise to the Company’s interest in restraining the Participant from competing and that the restrictive covenants are designed to enforce the Participant’s consideration or return promises under this Award Agreement. Additionally, the Participant acknowledges that these restrictive covenants contain limitations as to time, geographical area, and scope of activity to be restrained that are reasonable and do not impose a greater restraint than is necessary to protect the goodwill or other legitimate business interests of the Company, including, but not limited to, the Company’s need to protect its Confidential Information.

(e)Violations. If the Participant violates any provision of this Section 9, the Participant shall not be entitled to receive any amounts that would otherwise be payable to the Participant with respect to this Award, and such amounts shall be forfeited. If the Participant violates any provision of this Section 9 after amounts under this Award have been paid or if the Company learns of the violation after amounts under this Award have been paid, the Participant shall repay to the Company the Common Shares (or the equivalent value thereof determined as of the date of the Company’s demand) or the cash received, as the case may be, within thirty (30) days of receiving a demand from the Company for the repayment of the Award. Further, the Company shall be entitled to an award of attorneys’ fees incurred with securing any relief hereunder and/or pursuant to a breach or threatened breach of this Section 9.

10.Notices. For purposes of this Award Agreement, notices to the Company shall be deemed to have been duly given upon receipt of written notice by the Corporate Secretary of CenterPoint Energy, Inc., 1111 Louisiana, Houston, Texas 77002, or to such other address as the Company may furnish to the Participant.

Notices to the Participant shall be deemed effectively delivered or given upon personal, electronic, or postal delivery of written notice to the Participant, the place of Employment of the Participant, the address on record for the Participant at the human resources department of the Company, or such other address as the Participant hereafter designates by written notice to the Company.

11.Shareholder Rights. The Participant shall have no rights of a shareholder with respect to the Target Shares, unless and until the Participant is registered as the holder of shares of Common Stock.

12.Successors and Assigns. This Award Agreement shall bind and inure to the benefit of and be enforceable by the Participant, the Company and their respective permitted successors and assigns except as expressly prohibited herein and in the Plan. Notwithstanding anything herein or in the Plan to the contrary, the Target Shares are transferable by the Participant to Immediate Family Members, Immediate Family Member trusts, and Immediate Family Member partnerships pursuant to Section 13 of the Plan.

13.No Employment Guaranteed. Nothing in this Award Agreement shall give the Participant any rights to (or impose any obligations for) continued Employment by the Company or any Subsidiary or any successor thereto, nor shall it give such entities any rights (or impose any obligations) with respect to continued performance of duties by the Participant.

14.Waiver. Failure of either party to demand strict compliance with any of the terms or conditions hereof shall not be deemed a waiver of such term or condition, nor shall any waiver by either party of any right hereunder at any one time or more times be deemed a waiver of such right at any other time or times. No term or condition hereof shall be deemed to have been waived except by written instrument.

15.Compliance with Section 409A.It is the intent of the Company and the Participant that the provisions of the Plan and this Award Agreement comply with Section 409A and will be interpreted and administered consistent therewith. Accordingly, (i) no adjustment to the Award pursuant to Section 14 of the Plan and (ii) no substitutions of the benefits under this Award Agreement, in each case, shall be made in a manner that results in noncompliance with the requirements of Section 409A, to the extent applicable.

16.Compliance with Recoupment Policy. Any amounts payable, paid, or distributed under this Award Agreement are subject to the recoupment policy of the Company as in effect from time to time.

17.Modification of Award Agreement. Any modification of this Award Agreement shall be binding only if evidenced in writing and signed by an authorized representative of the Company.

EX-10.Q5

Exhibit 10(q)(5)

CENTERPOINT ENERGY, INC.

2009 LONG TERM INCENTIVE PLAN

FORM OF RESTRICTED STOCK UNIT AWARD AGREEMENT

FOR OFFICERS AND DIRECTOR EMPLOYEES

Pursuant to this Restricted Stock Unit Award Agreement (“Award Agreement”), CENTERPOINT ENERGY, INC. (the “Company”) hereby grants to <first_name> <last_name>, an employee of the Company, on <award_date> (the “Award Date”), a restricted stock unit award of <shares_awarded> units of Common Stock of the Company (the “RSU Award”) pursuant to the CENTERPOINT ENERGY, INC. 2009 LONG TERM INCENTIVE PLAN (the “Plan”), subject to the terms, conditions and restrictions described in the Plan and as follows:

1.Relationship to the Plan; Definitions. This RSU Award is subject to all of the terms, conditions and provisions of the Plan in effect on the date hereof and administrative interpretations thereunder, if any, adopted by the Committee. Except as defined herein, capitalized terms shall have the same meanings ascribed to them under the Plan. To the extent that any provision of this Award Agreement conflicts with the express terms of the Plan, it is hereby acknowledged and agreed that the terms of the Plan shall control and, if necessary, the applicable provisions of this Award Agreement shall be hereby deemed amended so as to carry out the purpose and intent of the Plan. References to the Participant herein also include the heirs or other legal representatives of the Participant. For purposes of this Award Agreement:

“Award Date”means the date this RSU Award is granted to the Participant as specified in this Award Agreement.

“Cause” means the Participant's (a) gross negligence in the performance of his or her duties, (b) intentional and continued failure to perform his or her duties, (c) intentional engagement in conduct which is materially injurious to the Company or its Subsidiaries (monetarily or otherwise) or (d) conviction of a felony or a misdemeanor involving moral turpitude. For this purpose, an act or failure to act on the part of the Participant will be deemed “intentional” only if done or omitted to be done by the Participant not in good faith and without reasonable belief that his or her action or omission was in the best interest of the Company, and no act or failure to act on the part of the Participant will be deemed “intentional” if it was due primarily to an error in judgment or negligence.

“Change in Control Closing Date” means the date a Change in Control is consummated.

“Change in Control Payment Date” means the following:

(a)If the Change in Control is a Section 409A Change in Control, then the Change in Control Payment Date shall be not later than the 70th day after the Change in Control Closing Date; and

(b)If the Change in Control is a Non-Section 409A Change in Control, then the Change in Control Payment Date shall be the Vesting Date(s) on which the units are paid under Section 3 hereof for the number of units indicated in Section 3 assuming continuous Employment by the Participant as of such Vesting Date(s); provided, however, in the case of the Participant’s death or Separation from Service prior to the Vesting Date(s), all shares not previously paid shall be paid not later than the 70th day after the Participant’s Termination Date except as otherwise provided in Section 7.

“Covered Termination” means a Separation from Service that occurs within two years after the date upon which a Change in Control occurs and that does not result from any of the following:

(a)death;

(b)Disability;

(c)involuntary termination for Cause; or

(d)resignation by the Participant, unless such resignation is for Good Reason.

“Disability” means that the Participant is both eligible for and in receipt of benefits under the Company's long-term disability plan.

“Employment” means employment with the Company or any of its Subsidiaries.

“Good Reason” means any one or more of the following events:

(a)a failure to maintain the Participant in the position, or a substantially equivalent position, with the Company and/or a Subsidiary, as the case may be, which the Participant held immediately prior to the Change in Control;

(b)a significant adverse change in the authorities, powers, functions, responsibilities, duties, or reporting structure which the Participant held immediately prior to the Change in Control;

(c)a significant reduction in the Participant’s annual base salary as in effect immediately prior to the date on which a Change in Control occurs;

(d)a significant reduction in the Participant’s qualified retirement benefits, nonqualified benefits and welfare benefits provided to the Participant immediately prior to the date on which a Change in Control occurs; provided, however, that a contemporaneous diminution of or reduction in qualified retirement benefits and/or welfare benefits which is of general application and which uniformly and contemporaneously reduces or diminishes the benefits of all covered employees shall be ignored and not be considered a reduction in remuneration for purposes of this paragraph (d);

(e)a significant reduction in the Participant’s overall compensation opportunities (as contrasted with overall compensation actually paid or awarded) under a short-term incentive plan, a long-term incentive plan or other equity plan (or in such substitute or alternative plans) from that provided to the Participant immediately prior to the date on which a Change in Control occurs;

(f)a change in the location of the Participant’s principal place of employment with the Company by more than 50 miles from the location where the Participant was principally employed immediately prior to the date on which a Change in Control occurs; or

(g)a failure by the Company to provide directors and officers liability insurance covering the Participant comparable to that provided to the Participant immediately prior to the date on which a Change in Control occurs;

provided, however, that no later than 30 days after learning of the action (or inaction) described herein as the basis for a termination of employment for Good Reason, the Participant shall advise the Company in writing that the action (or inaction) constitutes grounds for a termination of his or her Employment for Good Reason, in which event the Company shall have 30 days (the “Cure Period”) to correct such action (or inaction). If such action (or inaction) is not corrected prior to the end of the Cure Period, then the Participant may terminate his or her Employment with the Company for Good Reason within the 30-day period following the end of the Cure Period by giving written notice to the Company. If such action (or inaction) is corrected before the end of the Cure Period, then the Participant shall not be entitled to terminate his or her Employment for Good Reason as a result of such action (or inaction).

“Non-Section 409A Change in Control” means a Change in Control that is not a Section 409A Change in Control.

“Retirement”means a Separation from Service (a) on or after attainment of age 55 and (b) with at least five years of Employment; provided, however, that such Separation from Service is not by the Company for Cause or due to Disability.

“Sale of a Subsidiary” means, with respect to the Subsidiary for which the Participant is performing services at the time of the applicable event, the occurrence of any of the following events:

(a)A change in the ownership of such Subsidiary, as determined in accordance with Treasury Regulation § 1.409A-3(i)(5)(v) or

(b)A change in the ownership of a substantial portion of such Subsidiary’s assets, as determined in accordance with Treasury Regulation § 1.409A-3(i)(5)(vii).

If the Subsidiary is not a corporation, the above referenced Treasury Regulations may be applied by analogy in accordance with guidance issued under Section 409A.

“Section 16 Officer” means a Participant who is an “officer” within the meaning of Section 16 of the Exchange Act as of the date notice of the Participant’s Retirement is provided in accordance with Section 4(c).

“Section 409A” means Code Section 409A and the Treasury regulations and guidance issued thereunder.

“Section 409A Change in Control” means a Change in Control that satisfies the requirements of a change in control for purposes of Code Section 409A(a)(2)(A)(v) and the Treasury regulations and guidance issued thereunder.

“Separation from Service” means a separation from service with the Company or any of its Subsidiaries within the meaning of Treasury Regulation § 1.409A-1(h) (or any successor regulation).

“Termination Date” means the date of the Participant's Separation from Service.

“Vesting Date” means one or more vesting dates as specified in Section 3.

2.Establishment of RSU Award Account. The grant of units of Common Stock of the Company pursuant to this Award Agreement shall be implemented by a credit to a bookkeeping account maintained by the Company evidencing the accrual in favor of the Participant of the unfunded and unsecured right to receive a corresponding number of shares of Common Stock, which right shall be subject to the terms, conditions and restrictions set forth in the Plan and to the further terms, conditions and restrictions set forth in this Award Agreement. Except as otherwise provided in Section 12 of this Award Agreement, the units of Common Stock credited to the Participant's bookkeeping account may not be sold, assigned, transferred, pledged or otherwise encumbered until the Participant has been registered as the holder of shares of Common Stock on the records of the Company, as provided in Sections 4, 5 6, or 7 of this Award Agreement.

3.Vesting of RSU Award.Unless earlier (a) vested or forfeited pursuant to this Section 3 or Section 4 below or (b) vested in connection with a Change in Control pursuant to Section 5 below, the Participant's right to receive shares of Common Stock under this Award Agreement shall vest with respect to the number of units and on the Vesting Date(s) as shown in the following schedule:

<vesting_schedule>

Except as provided in Sections 4 and 5 below, the Participant must be in continuous Employment during the period beginning on the Award Date and ending on the Vesting Date(s) in order for the units (as indicated above) of the RSU Award to vest on such Vesting Date(s); otherwise, all unvested units shall be forfeited as of the Participant's Termination Date.

4.Effect of Separation from Service; Timing of Distribution.

(a)Death or Disability. Notwithstanding Section 3 above, if the Participant’s Termination Date occurs prior to (i) the final Vesting Date and (ii) the occurrence of a vesting event described in Section 5(b), 5(c), or 5(d) (in connection with a Change in Control or a Sale of a Subsidiary), and is due to the Participant’s death or Separation from Service due to Disability, then the Participant shall vest in the right to receive the total number of unvested units of Common Stock subject to this Award Agreement.

(b)Retirement. Notwithstanding Section 3 above, if the Participant's Termination Date occurs prior to (i) the final Vesting Date and (ii) the occurrence of a vesting event described in Section 5(b), 5(c), or 5(d) (in connection with a Change in Control or a Sale of a Subsidiary), and is due to the Participant's Separation from Service due to Retirement, then the Participant shall vest in the right to receive a number of the shares of Common Stock (rounded up to the nearest whole share) with respect to the unvested portion of this RSU Award determined by multiplying (A) the total number of units of Common Stock covered by this RSU Award by (B) a fraction, the numerator of which is the number of days that have elapsed from the Award Date to the Participant's Termination Date, and the denominator of which is the total number of days from the Award Date until the final Vesting Date.

(c)Enhanced Retirement. If the Participant is otherwise entitled to a benefit pursuant to Section 4(b) hereof due to the Participant’s Retirement and the requirements set forth under paragraph (1) or (2) below, as applicable, are satisfied, then in lieu of the benefits set forth in Section 4(b), the Participant shall vest, upon Retirement, in the right to receive the total number of unvested units of Common Stock subject to this Award Agreement.

(1)This paragraph (1) applies if the Participant is not a Section 16 Officer at the time of Retirement, and the requirements of this paragraph are satisfied if:

(i) the sum of the Participants age and years of Employment is 65 or greater;

(ii) the Participant’s Termination Date occurs on or after the January 1 immediately following the Award Date;

(iii) the Participant provides to the Company a transition plan; and

(iv) the Participant provides the Company at least six months’ written notice of the Participant’s Retirement.

(1)This paragraph (2) applies if the Participant is a Section 16 Officer at the time of Retirement, and the requirements of this paragraph are satisfied if: (x) the Participant satisfies (i), (ii), and (iii) under paragraph (1) above; (y) the Participant provides reasonable advance written notice (as determined by the Committee) of the Participant’s Retirement to the Chief Human Resources officer; and (z) the Committee approves providing the benefits set forth in this Section 4(c) above. Any such approval must occur prior to the Participant’s Termination Date and is at the sole discretion of the Committee.

(d)Timing of Distribution.

a.Death or Disability. If the Participant is entitled to a benefit pursuant to Section 4(a) hereof due to the Participant's death or Separation from Service due to Disability, then the number of shares of Common Stock determined in accordance with the applicable provision of this Section 4 shall be distributed not later than the 70th day after the Participant’s Termination Date except as otherwise provided in Section 7.

b.Retirement. If the Participant is entitled to a benefit pursuant to Section 4(b) or Section 4(c) hereof due to the Participant's Separation from Service due to Retirement, then the number of shares of Common Stock determined in accordance with Section 4(b) or Section 4(c), as applicable, shall be distributed on or within 70 days after the Vesting Date(s) upon which such units would be paid under Section 3 hereof assuming continuous Employment by the Participant as of such Vesting Date(s) or if a Change in Control that is a Section 409A Change in Control occurs earlier, on or within 70 days after the Change in Control Closing Date.

(e)Dividend Equivalents. Upon the date of distribution of shares of Common Stock under this Section 4, the Participant shall also be entitled to receive Dividend Equivalents for the period from the Award Date to the date such vested shares of Common Stock are distributed to the Participant (in accordance with the requirements of Section 409A, to the extent applicable).

5.Change in Control.

(a)Assumption or Substitution. In the event of a Change in Control, the surviving, continuing, successor, or purchasing corporation or other business entity or parent thereof, as the case may be (the "Acquiror"), may, without the Participant’s consent, either assume or continue the Company’s rights and obligations under this Award Agreement or provide a substantially equivalent award in substitution for the units subject to this RSU Award.

(b)Vesting Upon a Change in Control. Notwithstanding any provision of this Award Agreement to the contrary, if (i) there is a Change in Control and the Change in Control Closing Date occurs during the Participant's Employment and prior to the final Vesting Date and any vesting event under Section 4 above and (ii) the Acquiror does not assume or continue this RSU Award or provide a substantially equivalent award in substitution for this RSU Award pursuant to Section 5(a), then, upon the Change in Control Closing Date, the Participant's right to receive the unvested units of Common Stock subject to this Award Agreement shall be fully vested.

(c)Vesting Upon a Covered Termination. Notwithstanding any provision of this Award Agreement to the contrary, if the Participant experiences a Covered Termination prior to the final Vesting Date, then, upon the date of the Covered Termination, the Participant's right to receive any unvested units of Common Stock subject to this Award Agreement shall be fully vested.

(d)Vesting Upon the Sale of a Subsidiary. Notwithstanding any provision of this Award Agreement to the contrary, if (i) there is a Sale of a Subsidiary with respect to the Participant prior to the final Vesting Date and (ii) the Participant’s employment with the Company and all Subsidiaries (other than any entity that ceases to be a Subsidiary as a result of the Sale of a Subsidiary) ceases upon and in connection with such Sale of a Subsidiary, then upon such Sale of a Subsidiary, the Participant shall vest in the right to receive a number of the shares of Common Stock (rounded up to the nearest whole share) with respect to the unvested portion of this RSU Award determined by multiplying (A) the total number of units of Common Stock covered by this RSU Award by (B) a fraction, the numerator of which is the number of days that have elapsed from the Award Date to the date the Sale of a Subsidiary is consummated, and the denominator of which is the total number of days from the Award Date until the final Vesting Date. The Participant’s right to receive any additional shares pursuant to this Award Agreement shall be forfeited at such time.

(e)Distributions Upon a Change in Control or Sale of a Subsidiary.If the Participant is entitled to a benefit pursuant to Section 5(b), 5(c), or 5(d) hereof, then this RSU Award shall be settled by one or more distributions to the Participant of:

(1)The number of units of Common Stock subject to this Award Agreement not previously vested or forfeited pursuant to Sections 3 or 4 above (or such pro-rated amount as set forth in Section 5(d), if applicable), plus

(2)Dividend Equivalents on such units of Common Stock in the form of shares of Common Stock (rounded up to the nearest whole share) for the period commencing on the Award Date and ending on the date immediately preceding the date of the distribution.

In lieu of the foregoing distribution in shares, the Committee, in its sole discretion, may direct that such distribution be made to the Participant in one or more cash payments equal to:

(1)The product of (i) the Fair Market Value per share of Common Stock on the date immediately preceding the date of the distribution and (ii) the number of units of Common Stock subject to this Award Agreement not previously vested or forfeited pursuant to Sections 3 or 4 above (or such pro-rated amount as set forth in Section 5(d), if applicable), plus

(2)Dividend Equivalents on such units of Common Stock for the period commencing on the Award Date and ending on the date immediately preceding the date of the distribution.

Such distribution under this Section 5, whether in the form of shares of Common Stock or, if directed by the Committee, in cash, shall satisfy the rights of the Participant and the obligations of the Company under this Award Agreement in full.

(f)Timing of Distribution.

(1)No Assumption or Substitution. If the Participant is entitled to a benefit pursuant to Section 5(b), distributions shall be made in accordance with Section 5(e) on the Change in Control Payment Date.

(2)Covered Termination. If the Participant is entitled to a benefit pursuant to Section 5(c) on account of a Covered Termination, distributions shall be made in accordance with Section 5(e) not later than the 70th day after the Participant’s Termination Date except as otherwise provided in Section 7.

(3)Sale of a Subsidiary. If the Participant is entitled to a benefit pursuant to Section 5(d), distributions shall be made in accordance with Section 5(e) not later than the 70th day after the date the Sale of a Subsidiary is consummated.

6.Payment of RSU Award Under Section 3. Upon the vesting of the Participant's right to receive a number of the shares of Common Stock pursuant to Section 3 under this Award Agreement, such shares of Common Stock will be distributed not later than the 70th day after the applicable Vesting Date. Moreover, upon the date of distribution of shares of Common Stock, the Participant shall also be entitled to receive Dividend Equivalents for the period commencing on the Award Date and ending on the date such vested shares of Common Stock are distributed to the Participant (in accordance with the requirements of Section 409A, to the extent applicable).

7.Delay of Distribution to Certain Participants. With respect to any benefits payable hereunder upon the Participant’s Separation from Service (other than a Separation from Service due to the Participant’s death), if as of the Participant’s Termination Date, the Participant is a “specified employee” (within the meaning of Section 409A(a)(2)(B)), then such benefits shall not be distributed until the date that is the earlier of (x) the second business day following the end of the six-month period commencing on the Participant's Termination Date or (y) the Participant's date of death, if death occurs during such six-month period.

8.Confidentiality. The Participant agrees that the terms of this Award Agreement are confidential and that any disclosure to anyone for any purpose whatsoever (save and except disclosure to financial institutions as part of a financial statement, financial, tax and legal advisors, or as required by law) by the Participant or his or her agents, representatives, heirs, children, spouse, employees or spokespersons shall be a breach of this Award Agreement and the Company may elect to revoke the grant made hereunder, seek damages, plus interest and reasonable attorneys' fees, and take any other lawful actions to enforce this Award Agreement.

9. Participant Obligations.

(a)Confidentiality. The Participant acknowledges that in the course of his or her employment with the Company, the Company agrees to provide to the Participant Confidential Information regarding the Company and the Company’s business and has previously provided the Participant other such Confidential Information. In return for this and other consideration, provided under this Award Agreement, the Participant agrees that he or she will not, while employed by the Company and thereafter, disclose or make available to any other person or entity, or use for his own personal gain, any Confidential Information, except for such disclosures as required in the performance of his or her duties hereunder or as may otherwise be required by law or legal process (in which case the Participant shall notify the Company of such legal or judicial proceeding by a non-governmental party as soon as practicable following his receipt of notice of such a proceeding, and permit the Company to seek to protect its interests and information). Nothing in this Award Agreement, however, limits or precludes Participant from making a good faith voluntary report, charge, complaint, or claim to or providing truthful testimony and documents as required by law or under oath pursuant to a subpoena, court order, or request by the Equal Employment Opportunity Commission, the National Labor Relations Board, the Occupational Safety and Health Administration, the Securities and Exchange Commission or any other federal, state, or local government agency or commission (“Government Agencies”). Participant further understands that this Award Agreement does not limit Participant’s ability to communicate with any Government Agencies or otherwise participate in any investigation or proceeding that may be conducted by any Government Agency, including providing documents or other information to the Government Agency, without notice to the Company. For purposes of this Award Agreement, “Confidential Information” shall mean any and all information, data and knowledge that has been created, discovered, developed or otherwise become known to the Company or any of its affiliates or ventures or in which property rights have been assigned or otherwise conveyed to the Company or any of its affiliates or ventures, which information, data or knowledge has commercial value in the business in which the Company is engaged, except such information, data or knowledge as is or becomes known to the public without violation of the terms of this Award Agreement. By way of illustration, but not limitation, Confidential Information includes business trade secrets, secrets concerning the Company’s plans and strategies, nonpublic information concerning material market opportunities, technical trade secrets, processes, formulas, know-how, improvements, discoveries, developments, designs, inventions, techniques, marketing plans, manuals, records of research, reports, memoranda, computer software, strategies, forecasts, new products, unpublished financial information, projections, licenses, prices, costs, and employee, customer and supplier lists or parts thereof.

(b)Return of Property. The Participant agrees that at the time of his or her Separation from Service, he or she will deliver to the Company (and will not keep in his or her possession, recreate or deliver to anyone else) all Confidential Information as well as all other devices, records, data, notes, reports, proposals, lists, correspondence, specifications, drawings, blueprints, sketches, materials, equipment, customer or client lists or information, or any other documents or property (including all reproductions of the aforementioned items) belonging to the Company or any of its affiliates or ventures, regardless of whether such items were prepared by the Participant.

(c)Non-Solicitation and Non-Competition.

(1)Non-Solicitation. For consideration provided under this Award Agreement, including, but not limited to the Company’s agreement to provide the Participant with Confidential Information (as defined in Section 9(a)) regarding the Company and the Company’s business, the Participant agrees that, while employed by the Company and for one year following his or her Separation from Service, he or she shall not, without the prior written consent of the Company, directly or indirectly, (i) hire or induce, entice or solicit (or attempt to induce, entice or solicit) any employee of the Company or any of its affiliates or ventures to leave the employment of the Company or any of its affiliates or ventures or (ii) solicit or attempt to solicit the business of any customer or acquisition prospect of the Company or any of its affiliates or ventures with whom the Participant had any actual contact while employed at the Company.

(2)Non-Competition. For consideration provided under this Award Agreement, including, but not limited to the Company’s agreement to provide the Participant with Confidential Information regarding the Company and the Company’s business, the Participant agrees that while employed by the Company and for one year following a Separation from Service he or she will not, without the prior written consent of the Company, acting alone or in conjunction with others, either directly or indirectly, engage in any business that is in competition with the Company or accept employment with or render services to such a business as an officer, agent, employee, independent contractor or consultant, or otherwise engage in activities that are in competition with the Company.

(3)Restricted Area. The restrictions contained in this Section 9(c) are limited to a 50-mile radius around any geographical area in which the Company engages (or has definite plans to engage) in operations or the marketing of its products or services at the time of the Participant’s Separation from Service.

(d)Restrictions Reasonable. The Participant acknowledges that the restrictive covenants under this Section 9, for which the Participant received valuable consideration from the Company as provided in this Award Agreement, including, but not limited to the Company’s agreement to provide the Participant with Confidential Information regarding the Company and the Company’s business are ancillary to otherwise enforceable provisions of this Award Agreement that the consideration provided by the Company gives rise to the Company’s interest in restraining the Participant from competing and that the restrictive covenants are designed to enforce the Participant’s consideration or return promises under this Award Agreement. Additionally, the Participant acknowledges that these restrictive covenants contain limitations as to time, geographical area, and scope of activity to be restrained that are reasonable and do not impose a greater restraint than is necessary to protect the goodwill or other legitimate business interests of the Company, including, but not limited to, the Company’s need to protect its Confidential Information.

(e)Violations. If the Participant violates any provision of this Section 9, the Participant shall not be entitled to receive any amounts that would otherwise be payable to the Participant with respect to this RSU Award, and such amounts shall be forfeited. If the Participant violates any provision of this Section 9 after amounts under this RSU Award have been paid or if the Company learns of the violation after amounts under this RSU Award have been paid, the Participant shall repay to the Company the Common Shares (or the equivalent value thereof determined as of the date of the Company’s demand) or the cash received, as the case may be, within thirty (30) days of receiving a demand from the Company for the repayment of the award. Further, the Company shall be entitled to an award of attorneys’ fees incurred with securing any relief hereunder and/or pursuant to a breach or threatened breach of this Section 9.

10.Notices. For purposes of this Award Agreement, notices to the Company shall be deemed to have been duly given upon receipt of written notice by the Corporate Secretary of CenterPoint Energy, Inc., 1111 Louisiana, Houston, Texas 77002, or to such other address as the Company may furnish to the Participant.

Notices to the Participant shall be deemed effectively delivered or given upon personal, electronic, or postal delivery of written notice to the Participant, the place of Employment of the Participant, the address on record for the Participant at the human resources department of the Company, or such other address as the Participant hereafter designates by written notice to the Company.

11.Shareholder Rights. The Participant shall have no rights of a shareholder with respect to the units of Common Stock subject to this Award Agreement, unless and until the Participant is registered as the holder of such shares of Common Stock.

12.Successors and Assigns. This Award Agreement shall bind and inure to the benefit of and be enforceable by the Participant, the Company and their respective permitted successors and assigns except as expressly prohibited herein and in the Plan. Notwithstanding anything herein or in the Plan to the contrary, the units of Common Stock are transferable by the Participant to Immediate Family Members, Immediate Family Member trusts, and Immediate Family Member partnerships pursuant to Section 13 of the Plan.

13.No Employment Guaranteed. Nothing in this Award Agreement shall give the Participant any rights to (or impose any obligations for) continued Employment by the Company orany Subsidiary, or any successor thereto, nor shall it give such entities any rights (or impose any obligations) with respect to continued performance of duties by the Participant.

14.Waiver. Failure of either party to demand strict compliance with any of the terms or conditions hereof shall not be deemed a waiver of such term or condition, nor shall any waiver by either party of any right hereunder at any one time or more times be deemed a waiver of such right at any other time or times. No term or condition hereof shall be deemed to have been waived except by written instrument.

15.Compliance with Section 409A.It is the intent of the Company and the Participant that the provisions of the Plan and this Award Agreement comply with Section 409A and will be interpreted and administered consistent therewith. Accordingly, (i) no adjustment to the RSU Award pursuant to Section 14 of the Plan and (ii) no substitutions of the benefits under this Award Agreement, in each case, shall be made in a manner that results in noncompliance with the requirements of Section 409A, to the extent applicable.

16.Withholding. The Company shall have the right to withhold applicable taxes from any distribution of the Common Stock (including, but not limited to, Dividend Equivalents) or from other cash compensation payable to the Participant at the time of such vesting and delivery pursuant to Section 11 of the Plan (but subject to compliance with the requirements of Section 409A, if applicable).

17.Modification of Award Agreement. Any modification of this Award Agreement is subject to Section 13 hereof and shall be binding only if evidenced in writing and signed by an authorized representative of the Company.

EX-10.Q6

Exhibit 10(q)(6)

CENTERPOINT ENERGY, INC.

2009 LONG TERM INCENTIVE PLAN

RESTRICTED STOCK UNIT AWARD AGREEMENT

Pursuant to this Restricted Stock Unit Award Agreement (this “RSU Award Agreement”), CENTERPOINT ENERGY, INC. (the "Company") hereby grants to [Name] (the “Participant”), effective on [Date] (the “Grant Date”), a restricted stock unit award of [Number] units of Common Stock of the Company (the "RSU Award"), pursuant to the CENTERPOINT ENERGY, INC. 2009 LONG TERM INCENTIVE PLAN (the "Plan"), with such number of units being subject to adjustment as provided in Section 14 of the Plan, and further subject to the terms, conditions and restrictions described in the Plan and as follows:

1.Relationship to the Plan; Definitions. This RSU Award is subject to all of the terms, conditions and provisions of the Plan and administrative interpretations thereunder, if any, which have been adopted by the Committee and are in effect on the date hereof. Except as defined herein, capitalized terms shall have the same meanings ascribed to them under the Plan. To the extent that any provision of this RSU Award Agreement conflicts with the express terms of the Plan, it is hereby acknowledged and agreed that the terms of the Plan shall control and, if necessary, the applicable provisions of this RSU Award Agreement shall be hereby deemed amended so as to carry out the purpose and intent of the Plan. References to the Participant herein also include the heirs or other legal representatives of the Participant.

2.Establishment of RSU Award Account. The grant of units of Common Stock of the Company pursuant to this RSU Award Agreement shall be implemented by a credit to a bookkeeping account maintained by the Company evidencing the accrual in favor of the Participant of the unfunded and unsecured right to receive a corresponding number of shares of Common Stock, which right shall be subject to the terms, conditions and restrictions set forth in the Plan and to the further terms, conditions and restrictions set forth in this RSU Award Agreement. Except as otherwise provided in Section 10 of this RSU Award Agreement, the units of Common Stock credited to the Participant's bookkeeping account may not be sold, assigned, transferred, pledged or otherwise encumbered until the Participant has been registered as the holder of such shares of Common Stock on the records of the Company as provided in Section 4 or 5 of this RSU Award Agreement.

3.Vesting of RSU Award. Unless Participant receives a distribution pursuant to Section 4 below, the Participant's right to receive shares of Common Stock under this RSU Award shall vest as follows:

a.[Number] units of Common Stock of the Company covered under the RSU Award shall vest onthe [Years] anniversary of the Grant Date; and

b.[Number] units of Common Stock of the Company covered under the RSU Award shall vest on the [Years] anniversary of the Grant Date, such that 100% of the RSU Award shall be vested as of the [Years] anniversary of the Grant Date.

The Participant must be in continuous employment with the Company or any of its Subsidiaries ("Employment") from the Grant Date through and as of the applicable vesting date for the Common Stock to vest; otherwise, all such unvested shares as of the date the Participant's Employment terminates for any reason shall be forfeited as of such termination date.

4.Change in Control.

(a)Assumption or Substitution. In the event of a Change in Control, the surviving, continuing, successor, or purchasing corporation or other business entity or parent thereof, as the case may be (the "Acquiror"), may, without the Participant’s consent, either assume or continue the Company’s rights and obligations under this RSU Award Agreement or provide a substantially equivalent award in substitution for the units subject to this RSU Award.

(b)Vesting Upon a Change in Control. Notwithstanding any provision of this RSU Award Agreement to the contrary, upon the occurrence of a Change in Control of the Company, if (i) the Participant's Employment has not terminated prior to such date and (ii) the Acquiror does not assume or continue this RSU Award or provide a substantially equivalent award in substitution for this RSU Award pursuant to Section 4(a), the Participant's right to receive the unvested shares of Common Stock subject to this RSUAward Agreement shall be fully vested.

(c)Vesting Upon a Covered Termination. Notwithstanding any provision of this RSU Award Agreement to the contrary, if the Participant experiences a Covered Termination prior to the final vesting date, then, upon the date of the Covered Termination, the Participant's right to receive any unvested units of Common Stock subject to this RSU Award Agreement shall be fully vested.

(d)Vesting Upon the Sale of a Subsidiary. Notwithstanding any provision of this RSU Award Agreement to the contrary, if (i) there is a Sale of a Subsidiary with respect to the Participant prior to the final vesting date and (ii) the Participant’s employment with the Company and all Subsidiaries (other than any entity that ceases to be a Subsidiary as a result of the Sale of a Subsidiary) ceases upon and in connection with such Sale of a Subsidiary, then upon such Sale of a Subsidiary, the Participant shall vest in the right to receive a number of the shares of Common Stock (rounded up to the nearest whole share) with respect to the unvested portion of this RSU Award determined by multiplying (A) the total number of units of Common Stock covered by this RSU Award by (B) a fraction, the numerator of which is the number of days that have elapsed from the Award Date to the date the Sale of a Subsidiary is consummated, and the denominator of which is the total number of days from the Award Date until the final Vesting Date. The Participant’s right to receive any additional shares pursuant to this Award Agreement shall be forfeited at such time.

(e)Distributions Upon a Change in Control or Sale of a Subsidiary.If the Participant is entitled to a benefit pursuant to Section 4(b), 4(c), or 4(d) hereof, then this RSU Award shall be settled by a distribution to the Participant of:

a.the number of shares of Common Stock subject to this RSUAward Agreement not previously vested pursuant to Section 3 above (or such pro-rated amount as set forth in Section 4(d), if applicable), plus

b.Dividend Equivalents on such shares of Common Stock in the form of shares of Common Stock (rounded up to the nearest whole share) for the period commencing on the Grant Date and ending on the date immediately preceding the date of the distribution.

In lieu of the foregoing distribution in shares, the Committee, in its sole discretion, may direct that such distribution be made to the Participant in a lump sum cash payment equal to:

a.the product of (x) the Fair Market Value per share of Common Stock on the date immediately preceding the date of the distribution and (y) the number of shares of Common Stock subject to this RSUAward Agreement not previously vested pursuant to Section 3 above (or such pro-rated amount as set forth in Section 4(d), if applicable), plus

b.Dividend Equivalents on such shares of Common Stock for the period commencing on the Grant Date and ending on the date immediately preceding the date of the distribution;

The distribution under this Section 4, whether in the form of shares of Common Stock or, if directed by the Committee, in cash, shall satisfy the rights of the Participant and the obligations of the Company under this RSU Award Agreement in full.

(f)Timing of Distribution.

(1)No Assumption or Substitution. If the Participant is entitled to a benefit pursuant to Section 4(b), distributions shall be made in accordance with Section 4(e) on the Change in Control Payment Date.

(2)Covered Termination. If the Participant is entitled to a benefit pursuant to Section 4(c) on account of a Covered Termination, distributions shall be made in accordance with Section 4(e) not later than the 70th day after the Participant’s Covered Termination except as otherwise provided in Paragraph (4) below.

(3)Sale of a Subsidiary. If the Participant is entitled to a benefit pursuant to Section 4(d), distributions shall be made in accordance with Section 4(e) not later than the 70th day after the date the Sale of a Subsidiary is consummated.

(4)Delay of Distribution to Certain Participants.With respect to any benefits payable hereunder upon the Participant’s Separation from Service (including a Covered Termination), if as of the Participant’s Separation from Service, the Participant is a “specified employee” (within the meaning of Section 409A(a)(2)(B)), then such benefits shall not be distributed until the date that is the earlier of (x) the second business day following the end of the six-month period commencing on the date of the Participant's Separation from Service or (y) the Participant's date of death, if death occurs during such six-month period.

i. Definitions. For purposes of this Section 4:

“Change in Control Payment Date” means the following:

(i)If the Change in Control is a Section 409A Change in Control, then the Change in Control Payment Date shall be not later than the 70th day after the date the Change in Control is consummated; and

(ii)If the Change in Control is a Non-Section 409A Change in Control, then the Change in Control Payment Date shall be the vesting date(s) on which the units are paid under Section 3 hereof for the number of units indicated in Section 3 assuming continuous Employment by the Participant as of such vesting date(s); provided, however, in the case of the Participant’s death or Separation from Service prior to the vesting date(s), all shares not previously paid shall be paid not later than the 70th day after the date of the Participant’s Separation from Service except as otherwise provided in Section 4(f)(4).

“Covered Termination” means a Separation from Service that occurs within two years after the date upon which a Change in Control occurs and that does not result from any of the following:

(i)death;

(ii)Disability;

(iii)involuntary termination for Cause; or

(iv)resignation by the Participant, unless such resignation is for Good Reason.

“Disability” for this purpose means that the Participant is both eligible for and in receipt of benefits under the Company’s long-term disability plan. “Cause” means the Participant's (i) gross negligence in the performance of his or her duties, (ii) intentional and continued failure to perform his or her duties, (iii) intentional engagement in conduct which is materially injurious to the Company or its Subsidiaries (monetarily or otherwise) or (iv) conviction of a felony or a misdemeanor involving moral turpitude. For this purpose, an act or failure to act on the part of the Participant will be deemed “intentional” only if done or omitted to be done by the Participant not in good faith and without reasonable belief that his or her action or omission was in the best interest of the Company, and no act or failure to act on the part of the Participant will be deemed “intentional” if it was due primarily to an error in judgment or negligence.

“Good Reason” means any one or more of the following events:

(i)a failure to maintain the Participant in the position, or a substantially equivalent position, with the Company and/or a Subsidiary, as the case may be, which the Participant held immediately prior to the Change in Control;

(ii)a significant adverse change in the authorities, powers, functions, responsibilities, duties, or reporting structure which the Participant held immediately prior to the Change in Control;

(iii)a significant reduction in the Participant’s annual base salary as in effect immediately prior to the date on which a Change in Control occurs;

(iv)a significant reduction in the Participant’s qualified retirement benefits, nonqualified benefits and welfare benefits provided to the Participant immediately prior to the date on which a Change in Control occurs; provided, however, that a contemporaneous diminution of or reduction in qualified retirement benefits and/or welfare benefits which is of general application and which uniformly and contemporaneously reduces or diminishes the benefits of all covered employees shall be ignored and not be considered a reduction in remuneration for purposes of this paragraph (iv);

(v)a significant reduction in the Participant’s overall compensation opportunities (as contrasted with overall compensation actually paid or awarded) under a short-term incentive plan, a long-term incentive plan or other equity plan (or in such substitute or alternative plans) from that provided to the Participant immediately prior to the date on which a Change in Control occurs;

(vi)a change in the location of the Participant’s principal place of employment with the Company by more than 50 miles from the location where the Participant was principally employed immediately prior to the date on which a Change in Control occurs; or

(vii)a failure by the Company to provide directors and officers liability insurance covering the Participant comparable to that provided to the Participant immediately prior to the date on which a Change in Control occurs;

provided, however, that no later than 30 days after learning of the action (or inaction) described herein as the basis for a termination of employment for Good Reason, the Participant shall advise the Company in writing that the action (or inaction) constitutes grounds for a termination of his or her Employment for Good Reason, in which event the Company shall have 30 days (the “Cure Period”) to correct such action (or inaction). If such action (or inaction) is not corrected prior to the end of the Cure Period, then the Participant may terminate his or her Employment with the Company for Good Reason within the 30-day period following the end of the Cure Period by giving written notice to the Company. If such action (or inaction) is corrected before the end of the Cure Period, then the Participant shall not be entitled to terminate his or her Employment for Good Reason as a result of such action (or inaction).

“Non-Section 409A Change in Control” means a Change in Control that is not a Section 409A Change in Control.

“Sale of a Subsidiary” means, with respect to the Subsidiary for which the Participant is performing services at the time of the applicable event, the occurrence of any of the following events:

(a)A change in the ownership of such Subsidiary, as determined in accordance with Treasury Regulation § 1.409A-3(i)(5)(v) or

(b)A change in the ownership of a substantial portion of such Subsidiary’s assets, as determined in accordance with Treasury Regulation § 1.409A-3(i)(5)(vii).

If the Subsidiary is not a corporation, the above referenced Treasury Regulations may be applied by analogy in accordance with guidance issued under Section 409A.

“Section 409A” means Code Section 409A and the Treasury regulations and guidance issued thereunder.

“Section 409A Change in Control” means a Change in Control that satisfies the requirements of a change in control for purposes of Code Section 409A(a)(2)(A)(v) and the Treasury regulations and guidance issued thereunder.

“Separation from Service” means a separation from service with the Company or any of its Subsidiaries within the meaning of Treasury Regulation § 1.409A-1(h) (or any successor regulation).

5.Payment of Award Under Section 3. Upon the vesting of the Participant's right to receive the shares of Common Stock pursuant to Section 3 of this RSU Award Agreement, a number of shares of Common Stock equal to the number of vested units of Common Stock under this RSU Award Agreement shall be distributed not later than 70 days after the applicable vesting dates. Moreover, upon the date of distribution of shares of Common Stock in settlement of such units, the Participant shall also be entitled to receive Dividend Equivalents on such shares of Common Stock for the period from the Grant Date to the date such shares of Common Stock are distributed to the Participant (in accordance with the requirements of Section 409A of the Code, to the extent applicable).

6.Confidentiality. The Participant agrees that the terms of this RSU Award Agreement are confidential and that any disclosure to anyone for any purpose whatsoever (save and except disclosure to financial institutions as part of a financial statement, financial, tax and legal advisors, or as required by law) by the Participant or his or her agents, representatives, heirs, children, spouse, employees or spokespersons shall be a breach of this RSU Award Agreement and the Company may elect to revoke the grant made hereunder, seek damages, plus interest and reasonable attorneys' fees, and take any other lawful actions to enforce this RSU Award Agreement.

7. Participant Obligations.

a.Confidentiality. The Participant acknowledges that in the course of his or her employment with the Company, the Company agrees to provide to the Participant Confidential Information regarding the Company and the Company’s business and has previously provided the Participant other such Confidential Information. In return for this and other consideration, provided under this RSU Award Agreement, the Participant agrees that he or she will not, while employed by the Company and thereafter, disclose or make available to any other person or entity, or use for his own personal gain, any Confidential Information, except for such disclosures as required in the performance of his or her duties hereunder or as may otherwise be required by law or legal process (in which case the Participant shall notify the Company of such legal or judicial proceeding by a non-governmental party as soon as practicable following his receipt of notice of such a proceeding, and permit the Company to seek to protect its interests and information). Nothing in this RSU Award Agreement, however, limits or precludes Participant from making a good faith voluntary report, charge, complaint, or claim to or providing truthful testimony and documents as required by law or under oath pursuant to a subpoena, court order, or request by the Equal Employment Opportunity Commission, the National Labor Relations Board, the Occupational Safety and Health Administration, the Securities and Exchange Commission or any other federal, state, or local government agency or commission (“Government Agencies”). Participant further understands that this RSU Award Agreement does not limit Participant’s ability to communicate with any Government Agencies or otherwise participate in any investigation or proceeding that may be conducted by any Government Agency, including providing documents or other information to the Government Agency, without notice to the Company. For purposes of this RSU Award Agreement, “Confidential Information” shall mean any and all information, data and knowledge that has been created, discovered, developed or otherwise become known to the Company or any of its affiliates or ventures or in which property rights have been assigned or otherwise conveyed to the Company or any of its affiliates or ventures, which information, data or knowledge has commercial value in the business in which the Company is engaged, except such information, data or knowledge as is or becomes known to the public without violation of the terms of this RSU Award Agreement. By way of illustration, but not limitation, Confidential Information includes business trade secrets, secrets concerning the Company’s plans and strategies, nonpublic information concerning material market opportunities, technical trade secrets, processes, formulas, know-how, improvements, discoveries, developments, designs, inventions, techniques, marketing plans, manuals, records of research, reports, memoranda, computer software, strategies, forecasts, new products, unpublished financial information, projections, licenses, prices, costs, and employee, customer and supplier lists or parts thereof.

b.Return of Property. The Participant agrees that at the time of his or her Separation from Service, he or she will deliver to the Company (and will not keep in his or her possession, recreate or deliver to anyone else) all Confidential Information as well as all other devices, records, data, notes, reports, proposals, lists, correspondence, specifications, drawings, blueprints, sketches, materials, equipment, customer or client lists or information, or any other documents or property (including all reproductions of the aforementioned items) belonging to the Company or any of its affiliates or ventures, regardless of whether such items were prepared by the Participant.

c.Non-Solicitation and Non-Competition.

(1)Non-Solicitation. For consideration provided under this RSU Award Agreement, including, but not limited to the Company’s agreement to provide the Participant with Confidential Information (as defined in Section 7(a)) regarding the Company and the Company’s business, the Participant agrees that, while employed by the Company and for one year following his or her Separation from Service, he or she shall not, without the prior written consent of the Company, directly or indirectly, (i) hire or induce, entice or solicit (or attempt to induce, entice or solicit) any employee of the Company or any of its affiliates or ventures to leave the employment of the Company or any of its affiliates or ventures or (ii) solicit or attempt to solicit the business of any customer or acquisition prospect of the Company or any of its affiliates or ventures with whom the Participant had any actual contact while employed at the Company.

(2)Non-Competition. For consideration provided under this RSU Award Agreement, including, but not limited to the Company’s agreement to provide the Participant with Confidential Information regarding the Company and the Company’s business, the Participant agrees that while employed by the Company and for one year following a Separation from Service he or she will not, without the prior written consent of the Company, acting alone or in conjunction with others, either directly or indirectly, engage in any business that is in competition with the Company or accept employment with or render services to such a business as an officer, agent, employee, independent contractor or consultant, or otherwise engage in activities that are in competition with the Company.

(3)Restricted Area. The restrictions contained in this Section 7(c) are limited to a 50-mile radius around any geographical area in which the Company engages (or has definite plans to engage) in operations or the marketing of its products or services at the time of the Participant’s Separation from Service.

d.Restrictions Reasonable. The Participant acknowledges that the restrictive covenants under this Section 7, for which the Participant received valuable consideration from the Company as provided in this RSU Award Agreement, including, but not limited to the Company’s agreement to provide the Participant with Confidential Information regarding the Company and the Company’s business are ancillary to otherwise enforceable provisions of this RSU Award Agreement that the consideration provided by the Company gives rise to the Company’s interest in restraining the Participant from competing and that the restrictive covenants are designed to enforce the Participant’s consideration or return promises under this RSU Award Agreement. Additionally, the Participant acknowledges that these restrictive covenants contain limitations as to time, geographical area, and scope of activity to be restrained that are reasonable and do not impose a greater restraint than is necessary to protect the goodwill or other legitimate business interests of the Company, including, but not limited to, the Company’s need to protect its Confidential Information.

e.Violations. If the Participant violates any provision of this Section 7, the Participant shall not be entitled to receive any amounts that would otherwise be payable to the Participant with respect to this RSU Award, and such amounts shall be forfeited. If the Participant violates any provision of this Section 7 after amounts under this RSU Award have been paid or if the Company learns of the violation after amounts under this RSU Award have been paid, the Participant shall repay to the Company the Common Shares (or the equivalent value thereof determined as of the date of the Company’s demand) or the cash received, as the case may be, within thirty (30) days of receiving a demand from the Company for the repayment of the award. Further, the Company shall be entitled to an award of attorneys’ fees incurred with securing any relief hereunder and/or pursuant to a breach or threatened breach of this Section 7.

8.Notices. For purposes of this RSU Award Agreement, notices to the Company shall be deemed to have been duly given upon receipt of written notice by the Corporate Secretary of CenterPoint Energy, Inc., 1111 Louisiana, Houston, Texas 77002, or to such other address as the Company may furnish to the Participant.

Notices to the Participant shall be deemed effectively delivered or given upon personal, electronic, or postal delivery of written notice to the Participant, the place of Employment of the Participant, the address on record for the Participant at the human resources department of the Company, or such other address as the Participant hereafter designates by written notice to the Company.

9.Shareholder Rights. The Participant shall have no rights of a shareholder with respect to the shares of Common Stock granted pursuant to this RSU Award, unless and until the Participant is registered as the holder of such shares of Common Stock.

10.Successors and Assigns. This RSU Award Agreement shall bind and inure to the benefit of and be enforceable by the Participant, the Company and their respective permitted successors and assigns except as expressly prohibited herein and in the Plan. Notwithstanding anything herein or in the Plan to the contrary, the shares of Common Stock are transferable by the Participant to Immediate Family Members, Immediate Family Member trusts, and Immediate Family Member partnerships pursuant to Section 13 of the Plan.

11.No Employment Guaranteed. Nothing in this RSU Award Agreement shall give the Participant any rights to (or impose any obligations for) continued Employment by the Company orany Subsidiary, or any successor thereto, nor shall it give such entities any rights (or impose any obligations) with respect to continued performance of duties by the Participant.

12.Waiver. Failure of either party to demand strict compliance with any of the terms or conditions hereof shall not be deemed a waiver of such term or condition, nor shall any waiver by either party of any right hereunder at any one time or more times be deemed a waiver of such right at any other time or times. No term or condition hereof shall be deemed to have been waived except by written instrument.

13.Section 409A. It is the intent of the Company and the Participant that the provisions of the Plan and this Award Agreement comply with Section 409A of the Code and will be interpreted and administered consistent therewith. Accordingly, (i) no adjustment to the RSU Award pursuant to Section 14 of the Plan and (ii) no substitutions of the benefits under this Award Agreement, in each case, shall be made in a manner that results in noncompliance with the requirements of Section 409A of the Code, to the extent applicable.

14.Withholding.The Company shall have the right to withhold applicable taxes from any distribution of the Common Stock (including, but not limited to, Dividend Equivalents) or from other cash compensation payable to the Participant at the time of such vesting and delivery pursuant to Section 11 of the Plan (but subject to compliance with the requirements of Section 409A of the Code, if applicable).

15.Modification of RSU Award Agreement. Any modification of this RSU Award Agreement is subject to Section 13 hereof and shall be binding only if evidenced in writing.

1    

EX-10.(R)

Exhibit 10(r)

CenterPoint Energy, Inc.

Summary of Non-Employee Director Compensation

The following is a summary of compensation paid to the non-employee directors of CenterPoint Energy, Inc. (the “Company”) effective April 25, 2019. For additional information regarding the compensation of the non-employee directors, please read the definitive proxy statement relating to the Company’s 2020 annual meeting of shareholders to be filed pursuant to Regulation 14A.

• Annual retainer fee of $110,000 for Board membership, paid quarterly in arrears;

• Supplemental annual retainer of $20,000 for serving as a chairman of the Audit Committee or Compensation Committee; and

• Supplemental annual retainer of $15,000 for serving as a chairman of the Finance Committee or Governance Committee.

Stock Grants. Each non-employee director serving as of May 1, 2019 was granted an annual stock award under the CenterPoint Energy Inc. Stock Plan for Outside Directors in 2019. The cash value of these awards, as of the grant date, is set annually by the Board of Directors of the Company. The number of shares awarded is then determined by dividing the cash value by the fair market value of the common stock on the grant date. In 2019, the Board determined a cash value for the stock award, as of the grant date, of $150,000, resulting in a stock award to each non-employee director of 4,873 shares of common stock. The annual stock award granted in 2019 and any future stock awards under the Stock Plan for Outside Directors are immediately fully vested upon grant.

Deferred Compensation Plan. Directors may elect each year to defer all or part of their annual retainer fees, including any committee chairman fees and meeting fees. Directors participating in these plans may elect to receive distributions of their deferred compensation and interest in three ways: (i) an early distribution of either 50% or 100% of their deferrals for the year in any year that is at least four years from the year of deferral or, if earlier, the year in which they attain their normal retirement date under the plan (the first day of the month coincident with or next following attainment of age 70); (ii) a lump sum distribution payable in the year after they reach their normal retirement date or leave the Board of Directors, whichever is later; or (iii) 15 annual installments beginning on the first of the month coincident with or next following their normal retirement date or upon leaving the Board of Directors, whichever is later.

EX-10.(S)

Exhibit 10(s)

CenterPoint Energy, Inc.

Summary of Senior Executive Officer Compensation

The following is a summary of compensation paid to the Chief Executive Officer, Chief Financial Officer, Executive Vice President and President - Electric Division and Executive Vice President - Natural Gas Distribution identified below (to whom we collectively refer as our “senior executive officers”) of CenterPoint Energy, Inc. (the “Company”). For additional information regarding the compensation of the senior executive officers, please read the definitive proxy statement relating to the Company’s 2020 annual meeting of shareholders to be filed pursuant to Regulation 14A.

Base Salary. The following table sets forth the annual base salary of the Company’s senior executive officers effective April 1, 2020:

Name and Position	Base Salary
Scott M. Prochazka* President and Chief Executive Officer	$	1,323,000
Xia Liu Executive Vice President and Chief Financial Officer	$	620,000
Tracy B. Bridge** Executive Vice President and President - Electric Division	$	560,000
Scott E. Doyle Executive Vice President - Natural Gas Distribution	$	500,000

Short Term Incentive Plan. Annual bonuses are paid to the Company’s senior executive officers pursuant to the Company’s short term incentive plan, which provides for cash bonuses based on the achievement of certain performance objectives approved in accordance with the terms of the plan at the commencement of the year. Information regarding awards to the Company’s senior executive officers under the short term incentive plan is provided in definitive proxy statements relating to the Company’s annual meeting of shareholders. In February 2020, the Compensation Committee of the Company approved the following:

• No changes were made to Mr. Prochazka’s short-term incentive target of 115%*;

• No changes were made to Ms. Liu’s short-term incentive target of 75%;

• No changes were made to Mr. Bridge’s short-term incentive target of 75%**; and

• No changes were made to Mr. Doyle’s short-term incentive target of 65%.

Long Term Incentive Plan. Under the Company’s long term incentive plan, the Company’s senior executive officers may receive grants of (i) stock option awards, (ii) stock appreciation rights, (iii) stock awards, (iv) restricted stock unit awards, (v) cash awards and (vi) performance awards. The current forms of the applicable award agreements pursuant to the Company’s long term incentive plan are included as exhibits hereto. In February 2020, the Compensation Committee of the Company approved the following:

• No changes were made to Mr. Prochazka’s long-term incentive target of 450%*;

• Ms. Liu’s long-term incentive target was increased from 190% to 225%;

• No changes were made to Mr. Bridge’s long-term incentive target of 170%**; and

• Mr. Doyle’s long-term incentive target was increased from 150% to 170%.

* On February 19, 2020, Mr. Prochazka resigned from his position as President and Chief Executive Officer of the Company.

** On February 25, 2020, Mr. Bridge retired from his position as Executive Vice President and President - Electric Division of the Company.

EX-21

Exhibit 21

SIGNIFICANT SUBSIDIARIES OF CENTERPOINT ENERGY, INC.

The following subsidiaries are deemed “significant subsidiaries” pursuant to Item 601(b) (21) of Regulation S-K:

Utility Holding, LLC, a Delaware limited liability company and a direct wholly-owned subsidiary of CenterPoint Energy, Inc.

CenterPoint Energy Midstream, Inc., a Delaware corporation and a wholly-owned subsidiary of CenterPoint Energy, Inc.

CenterPoint Energy Houston Electric, LLC, a Texas limited liability company and an indirect wholly-owned subsidiary of CenterPoint Energy, Inc.

CenterPoint Energy Resources Corp., a Delaware corporation and an indirect wholly-owned subsidiary of CenterPoint Energy, Inc.

CenterPoint Energy Services, Inc., a Delaware corporation and a wholly-owned subsidiary of CenterPoint Energy Resources Corp.

CenterPoint Energy Investment Management, Inc., a Delaware corporation and an indirect wholly-owned subsidiary of CenterPoint Energy, Inc.

Vectren Corporation, an Indiana corporation and a wholly-owned subsidiary of CenterPoint Energy, Inc.

Vectren Utility Holdings, Inc., an Indiana corporation and a wholly-owned subsidiary of Vectren Corporation

Southern Indiana Gas and Electric Company, an Indiana corporation and a wholly-owned subsidiary of Vectren Utility Holdings, Inc. (doing business as Vectren Energy Delivery of Indiana, Inc.)

Indiana Gas Company, Inc., an Indiana corporation and a wholly-owned subsidiary of Vectren Utility Holdings, Inc. (doing business as Vectren Energy Delivery of Indiana, Inc.)

Vectren Energy Delivery of Ohio, Inc., an Ohio corporation and a wholly-owned subsidiary of Vectren Utility Holdings, Inc.

Vectren Enterprises, Inc., an Indiana corporation and a wholly-owned subsidiary of Vectren Corporation

Vectren Utility Services, Inc., an Indiana corporation and a wholly-owned subsidiary of Vectren Enterprises, Inc.

Vectren Infrastructure Services Corporation, an Indiana corporation and a wholly-owned subsidiary of Vectren Utility Services, Inc.

Miller Pipeline, LLC, an Indiana corporation and wholly-owned subsidiary of Vectren Infrastructure Services Corporation

Minnesota Limited, LLC, a Minnesota corporation and wholly-owned subsidiary of Vectren Infrastructure Services Corporation

(1) Pursuant to Item 601(b) (21) of Regulation S-K, registrant has omitted the names of subsidiaries, which considered in the aggregate as a single subsidiary, would not constitute a “significant subsidiary” (as defined under Rule 1-02(w) of Regulation S-X) as of December 31, 2019.

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement Nos. 333-233356 on Form S-3; Registration Statement Nos. 333-203201, as amended, 333-179310, 333-173660, 333-149757, 333-101202, as amended, 333-115976, as amended, 333-159586, as amended, and 333-105773, as amended on Form S-8; Post-Effective Amendment No. 1 to Registration Statement Nos. 333-32413-99, 333-49333-99, 333-38188-99, 333-60260-99 and 333-98271-99 on Form S-8; and Post-Effective Amendment No. 5 to Registration Statement No. 333-11329-99 on Form S-8 of our reports dated February 27, 2020, relating to the consolidated financial statements of CenterPoint Energy, Inc. and subsidiaries (the “Company”), and the effectiveness of the Company’s internal control over financial reporting, appearing in this Annual Report on Form 10-K of CenterPoint Energy, Inc. for the year ended December 31, 2019.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

February 27, 2020

EX-23.2

Exhibit 23.2

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement No. 333-233356 on Form S-3; Registration Statement Nos. 333-203201, as amended, 333-179310, 333-173660, 333-149757, 333-101202, as amended, 333-115976, as amended, 333-159586, as amended, and 333-105773, as amended on Form S-8; Post-Effective Amendment No. 1 to Registration Statement Nos. 333-32413-99, 333-49333-99, 333-38188-99, 333-60260-99 and 333-98271-99 on Form S-8; and Post-Effective Amendment No. 5 to Registration Statement No. 333-11329-99 on Form S-8 of CenterPoint Energy, Inc. of our report dated February 19, 2020, relating to the consolidated financial statements of Enable Midstream Partners, LP and subsidiaries, appearing in this Annual Report on Form 10-K of CenterPoint Energy, Inc. for the year ended December 31, 2019.

/s/ DELOITTE & TOUCHE LLP

Oklahoma City, Oklahoma

February 27, 2020

EX-31.1.1

Exhibit 31.1.1

CERTIFICATIONS

I, John W. Somerhalder II, certify that:

1.           I have reviewed this annual report on Form 10-K of CenterPoint Energy, Inc.;

2.           Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.           Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.           The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.           The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:       February 27, 2020

/s/ John W. Somerhalder II

John W. Somerhalder II

Interim President and Chief Executive Officer

EX-31.1.2

Exhibit 31.1.2

CERTIFICATIONS

I, John W. Somerhalder II, certify that:

1. I have reviewed this annual report on Form 10-K of CenterPoint Energy Houston Electric, LLC;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  February 27, 2020

/s/ John W. Somerhalder II

John W. Somerhalder II

Interim Manager and Chairman (Principal Executive Officer)

EX-31.1.3

Exhibit 31.1.3

CERTIFICATIONS

I, John W. Somerhalder II, certify that:

1.           I have reviewed this annual report on Form 10-K of CenterPoint Energy Resources Corp.;

2.           Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.           Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.           The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.           The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:  February 27, 2020

/s/ John W. Somerhalder II

John W. Somerhalder II

Interim President and Chief Executive Officer

EX-31.2.1

Exhibit 31.2.1

CERTIFICATIONS

I, Xia Liu, certify that:

1.           I have reviewed this annual report on Form 10-K of CenterPoint Energy, Inc.;

2.           Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.           Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.           The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.           The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:       February 27, 2020

/s/ Xia Liu

Xia Liu

Executive Vice President and Chief Financial Officer

EX-31.2.2

Exhibit 31.2.2

CERTIFICATIONS

I, Xia Liu, certify that:

1.I have reviewed this annual report on Form 10-K of CenterPoint Energy Houston Electric, LLC;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  February 27, 2020

/s/ Xia Liu

Xia Liu

Executive Vice President and Chief Financial Officer

EX-31.2.3

Exhibit 31.2.3

CERTIFICATIONS

I, Xia Liu, certify that:

1.           I have reviewed this annual report on Form 10-K of CenterPoint Energy Resources Corp.;

2.           Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.           Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.           The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.           The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:  February 27, 2020

/s/ Xia Liu

Xia Liu

Executive Vice President and Chief Financial Officer

EX-32.1.1

Exhibit 32.1.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of CenterPoint Energy, Inc. (the “Company”) on Form 10-K for the year ended December 31, 2019 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, John W. Somerhalder II, Chief Executive Officer, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

1.           The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2.           The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ John W. Somerhalder II

John W. Somerhalder II

Interim President and Chief Executive Officer

February 27, 2020

EX-32.1.2

Exhibit 32.1.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of CenterPoint Energy Houston Electric, LLC (the “Company”) on Form 10-K for the year ended December 31, 2019 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, John W. Somerhalder II, Chairman (Principal Executive Officer), certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

1.The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2.The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ John W. Somerhalder II

John W. Somerhalder II

Interim Manager and Chairman (Principal Executive Officer)

February 27, 2020

EX-32.1.3

Exhibit 32.1.3

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of CenterPoint Energy Resources Corp. (the “Company”) on Form 10-K for the year ended December 31, 2019 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, John W. Somerhalder II, Chief Executive Officer, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

1.           The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2.           The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ John W. Somerhalder II

John W. Somerhalder II

Interim President and Chief Executive Officer

February 27, 2020

EX-32.2.1

Exhibit 32.2.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of CenterPoint Energy, Inc. (the “Company”) on Form 10-K for the year ended December 31, 2019 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, Xia Liu, Chief Financial Officer, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

1.           The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2.           The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Xia Liu

Xia Liu

Executive Vice President and Chief Financial Officer

February 27, 2020

EX-32.2.2

Exhibit 32.2.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of CenterPoint Energy Houston Electric, LLC (the “Company”) on Form 10-K for the year ended December 31, 2019 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, Xia Liu, Chief Financial Officer, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

1.The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2.The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Xia Liu

Xia Liu

Executive Vice President and Chief Financial Officer

February 27, 2020

EX-32.2.3

Exhibit 32.2.3

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of CenterPoint Energy Resources Corp. (the “Company”) on Form 10-K for the year ended December 31, 2019 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, Xia Liu, Chief Financial Officer, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

1.           The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2.           The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Xia Liu

Xia Liu

Executive Vice President and Chief Financial Officer

February 27, 2020

XML

Derivative Instruments (Tables)

12 Months Ended

Dec. 31, 2019

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Notional Amounts of Outstanding Derivative Positions [Table Text Block]

The table below summarizes the Registrants’ outstanding interest rate hedging activity:

	December 31, 2019				December 31, 2018
Hedging Classification	Notional Principal
	CenterPoint  Energy (1)		Houston  Electric		CenterPoint  Energy		Houston  Electric
	(in millions)
Economic hedge	$	84	$	—	$	—	$	—
Cash flow hedge	—		—		450		450

(1)

Relates to interest rate derivative instruments at SIGECO.

Schedule of Fair Value Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block]

The tables below summarizes CenterPoint Energy’s and CERC’s weather hedge gain (loss) activity:

CenterPoint Energy

				Year Ended December 31,
Texas Operations	Winter Season	Bilateral Cap		2019		2018			2017
		(in millions)
NGD	2019 – 2020	$	8	$	2	$	—		$	—
NGD	2018 – 2019	9		—		—			—
NGD	2017 – 2018	8		—		(2		)	—
Electric operations	2019 – 2020	7		3		—			—
Electric operations	2018 – 2019	8		3		—			—
Electric operations	2017 – 2018	9		—		(2		)	—
Electric operations	2016 – 2017	9		—		—			(1		)
Total CenterPoint Energy (1)				$	8	$	(4	)	$	(1	)

CERC

				Year Ended December 31,
Texas Operations	Winter Season	Bilateral Cap		2019		2018			2017
		(in millions)
NGD	2019 – 2020	$	8	$	2	$	—		$	—
NGD	2018 – 2019	9		—		—			—
NGD	2017 – 2018	8		—		(2		)	—
Total CERC (1)				$	2	$	(2	)	$	—

(1)

Weather hedge gains (losses) are recorded in Revenues in the Statements of Consolidated Income.

Fair Value of Derivative Instruments [Table Text Block]

The following tables present information about derivative instruments and hedging activities. The first three tables provide a balance sheet overview of Derivative Assets and Liabilities as of December 31, 2019 and 2018, while the last two tables provide a breakdown of the related income statement impacts for the years ending December 31, 2019, 2018 and 2017.

Fair Value of Derivative Instruments and Hedged Items

CenterPoint Energy

		December 31, 2019				December 31, 2018
	Balance Sheet Location	Derivative Assets Fair Value		Derivative Liabilities Fair Value		Derivative Assets Fair Value		Derivative Liabilities Fair Value
		(in millions)
Derivatives designated as cash flow hedges:
Interest rate derivatives	Current Liabilities: Non-trading derivative liabilities	$	—	$	—	$	—	$	24
Derivatives designated as fair value hedges:
Natural gas derivatives (1) (2) (3)	Current Liabilities: Non-trading derivative liabilities	12		—		1		7
Derivatives not designated as hedging instruments:
Natural gas derivatives (1) (2) (3)	Current Assets: Non-trading derivative assets	139		3		103		3
Natural gas derivatives (1) (2) (3)	Other Assets: Non-trading derivative assets	58		—		38		—
Natural gas derivatives (1) (2) (3)	Current Liabilities: Non-trading derivative liabilities	73		184		62		173
Natural gas derivatives (1) (2) (3)	Other Liabilities: Non-trading derivative liabilities	10		54		16		25
Interest rate derivatives	Other Liabilities	—		10		—		—
Indexed debt securities derivative	Current Liabilities	—		893		—		601
Total CenterPoint Energy		$	292	$	1,144	$	220	$	833

(1) The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling 2,226 Bcf or a net 374 Bcf long position and 1,674 Bcf or a net 140 Bcf long position as of December 31, 2019 and 2018, respectively. Certain natural gas contracts hedge basis risk only and lack a fixed price exposure.

(2) Natural gas contracts are presented on a net basis in CenterPoint Energy’s Consolidated Balance Sheets as they are subject to master netting arrangements. This netting applies to all undisputed amounts due or past due and causes derivative assets (liabilities) to be ultimately presented net in a liability (asset) account within CenterPoint Energy’s Consolidated Balance Sheets. The net of total non-trading natural gas derivative assets and liabilities is detailed in the Offsetting of Natural Gas Derivative Assets and Liabilities table below.

(3) Derivative Assets and Derivative Liabilities include no material amounts related to physical forward transactions with Enable.

Houston Electric

		December 31, 2019				December 31, 2018
	Balance Sheet Location	Derivative Assets Fair Value		Derivative Liabilities Fair Value		Derivative Assets Fair Value		Derivative Liabilities Fair Value
		(in millions)
Derivatives designated as cash flow hedges:
Interest rate derivatives	Current Liabilities: Non-trading derivative liabilities	$	—	$	—	$	—	$	24
Total Houston Electric		$	—	$	—	$	—	$	24

CERC

		December 31, 2019				December 31, 2018
	Balance Sheet Location	Derivative Assets Fair Value		Derivative Liabilities Fair Value		Derivative Assets Fair Value		Derivative Liabilities Fair Value
		(in millions)
Derivatives designated as fair value hedges:
Natural gas derivatives (1) (2) (3)	Current Liabilities: Non-trading derivative liabilities	$	12	$	—	$	1	$	7
Derivatives not designated as hedging instruments:
Natural gas derivatives (1) (2) (3)	Current Assets: Non-trading derivative assets	139		3		103		3
Natural gas derivatives (1) (2) (3)	Other Assets: Non-trading derivative assets	58		—		38		—
Natural gas derivatives (1) (2) (3)	Current Liabilities: Non-trading derivative liabilities	73		177		62		173
Natural gas derivatives (1) (2) (3)	Other Liabilities: Non-trading derivative liabilities	10		39		16		25
Total CERC		$	292	$	219	$	220	$	208

(1) The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling 2,226 Bcf or a net 374 Bcf long position and 1,674 Bcf or a net 140 Bcf long position as of December 31, 2019 and 2018, respectively. Certain natural gas contracts hedge basis risk only and lack a fixed price exposure.

(2) Natural gas contracts are presented on a net basis in CERC’s Consolidated Balance Sheets as they are subject to master netting arrangements. This netting applies to all undisputed amounts due or past due and causes derivative assets (liabilities) to be ultimately presented net in a liability (asset) account within CERC’s Consolidated Balance Sheets. The net of total non-trading natural gas derivative assets and liabilities is detailed in the Offsetting of Natural Gas Derivative Assets and Liabilities table below.

(3) Derivative Assets and Derivative Liabilities include no material amounts related to physical forward transactions with Enable.

Cumulative Basis Adjustment for Fair Value Hedges (CenterPoint Energy and CERC)

CenterPoint Energy
		December 31, 2019					December 31, 2018
	Balance Sheet Location	Carrying Amount of Hedged Assets/(Liabilities)		Cumulative Amount of Fair Value Hedging Adjustment Included in the Carrying Amount of Hedged Item			Carrying Amount of Hedged Assets/(Liabilities)		Cumulative Amount of Fair Value Hedging Adjustment Included in the Carrying Amount of Hedged Item
		(in millions)
Hedged items in fair value hedge relationship:
Natural gas inventory	Current Assets: Natural gas inventory	$	47	$	(13	)	$	57	$	1
Total CenterPoint Energy		$	47	$	(13	)	$	57	$	1

CERC
		December 31, 2019					December 31, 2018
	Balance Sheet Location	Carrying Amount of Hedged Assets/(Liabilities)		Cumulative Amount of Fair Value Hedging Adjustment Included in the Carrying Amount of Hedged Item			Carrying Amount of Hedged Assets/(Liabilities)		Cumulative Amount of Fair Value Hedging Adjustment Included in the Carrying Amount of Hedged Item
		(in millions)
Hedged items in fair value hedge relationship:
Natural gas inventory	Current Assets: Natural gas inventory	$	47	$	(13	)	$	57	$	1
Total CERC		$	47	$	(13	)	$	57	$	1

Offsetting of Natural Gas Derivative Assets and Liabilities [Table Text Block]

CenterPoint Energy
	December 31, 2019									December 31, 2018
	Gross Amounts Recognized (1)			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amount Presented in the Consolidated Balance Sheets (2)			Gross Amounts Recognized (1)			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amount Presented in the Consolidated Balance Sheets (2)
	(in millions)
Current Assets: Non-trading derivative assets	$	224		$	(88	)	$	136		$	166		$	(66	)	$	100
Other Assets: Non-trading derivative assets	68			(10		)	58			54			(16		)	38
Current Liabilities: Non-trading derivative liabilities	(187		)	136			(51		)	(183		)	81			(102		)
Other Liabilities: Non-trading derivative liabilities	(54		)	25			(29		)	(25		)	20			(5		)
Total CenterPoint Energy	$	51		$	63		$	114		$	12		$	19		$	31

CERC
	December 31, 2019									December 31, 2018
	Gross Amounts Recognized (1)			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amount Presented in the Consolidated Balance Sheets (2)			Gross Amounts Recognized (1)			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amount Presented in the Consolidated Balance Sheets (2)
	(in millions)
Current Assets: Non-trading derivative assets	$	224		$	(88	)	$	136		$	166		$	(66	)	$	100
Other Assets: Non-trading derivative assets	68			(10		)	58			54			(16		)	38
Current Liabilities: Non-trading derivative liabilities	(180		)	136			(44		)	(183		)	81			(102		)
Other Liabilities: Non-trading derivative liabilities	(39		)	25			(14		)	(25		)	20			(5		)
Total CERC	$	73		$	63		$	136		$	12		$	19		$	31

(1) Gross amounts recognized include some derivative assets and liabilities that are not subject to master netting arrangements.

(2)

The derivative assets and liabilities on the Registrant’s respective Consolidated Balance Sheets exclude accounts receivable or accounts payable that, should they exist, could be used as offsets to these balances in the event of a default.

Income Statement Impact of Derivative Activity [Table Text Block]

Income Statement Impact of Hedge Accounting Activity (CenterPoint Energy and CERC)

CenterPoint Energy	Year Ended December 31,
	2019			2018			2017
	Location and Amount of Gain (Loss) recognized in Income on Hedging Relationship (1)
	Non-utility cost of revenues, including natural gas
	(in millions)
Total amounts presented in the statements of income in which the effects of hedges are recorded	$	4,029		$	4,364		$	3,785
Gain (loss) on fair value hedging relationships:
Commodity contracts:
Hedged items - Natural gas inventory	(14		)	(13		)	14
Derivatives designated as hedging instruments	14			13			(14		)
Amounts excluded from effectiveness testing recognized in earnings immediately	(213		)	(149		)	(67		)

(1) Income statement impact associated with cash flow hedge activity is related to gains and losses reclassified from Accumulated other comprehensive income into income. Amounts are immaterial for the years ended December 31, 2019, 2018 and 2017, respectively.

CERC	Year Ended December 31,
	2019			2018			2017
	Location and Amount of Gain (Loss) recognized in Income on Hedging Relationship (1)
	Non-utility cost of revenues, including natural gas
	(in millions)
Total amounts presented in the statements of income in which the effects of hedges are recorded	$	3,503		$	4,364		$	3,785
Gain (loss) on fair value hedging relationships:
Commodity contracts:
Hedged items - Natural gas inventory	(14		)	(13		)	14
Derivatives designated as hedging instruments	14			13			(14		)
Amounts excluded from effectiveness testing recognized in earnings immediately	(213		)	(149		)	(67		)

(1) Income statement impact associated with cash flow hedge activity is related to gains and losses reclassified from Accumulated other comprehensive income into income. Amounts are immaterial for the years ended December 31, 2019, 2018 and 2017, respectively.

CenterPoint Energy

		Year Ended December 31,
	Income Statement Location	2019			2018			2017
		(in millions)
Effects of derivatives not designated as hedging instruments on the income statement:
Commodity contracts	Gains (Losses) in Non-utility revenues	$	214		$	107		$	211
Indexed debt securities derivative	Gain (loss) on indexed debt securities	(292		)	(232		)	49
Interest rate derivatives	Gains in Other Income (Expense)	—			2			—
Total CenterPoint Energy		$	(78	)	$	(123	)	$	260

CERC

		Year Ended December 31,
	Income Statement Location	2019		2018		2017
		(in millions)
Effects of derivatives not designated as hedging instruments on the income statement:
Commodity contracts	Gains (Losses) in Non-utility revenues	$	214	$	107	$	211
Total CERC		$	214	$	107	$	211

Credit Quality of Counterparties [Table Text Block]

CenterPoint Energy and CERC enter into financial derivative contracts containing material adverse change provisions. These provisions could require CenterPoint Energy or CERC to post additional collateral if the S&P or Moody’s credit ratings of CenterPoint Energy, Inc. or its subsidiaries, including CERC Corp., are downgraded.  

	December 31, 2019				December 31, 2018
	CenterPoint Energy		CERC		CenterPoint Energy		CERC
	(in millions)
Aggregate fair value of derivatives containing material adverse change provisions in a net liability position	$	1	$	1	$	1	$	1
Fair value of collateral already posted	—		—		—		—
Additional collateral required to be posted if credit risk contingent features triggered	1		1		—		—

(d) Credit Quality of Counterparties (CenterPoint Energy and CERC)

In addition to the risk associated with price movements, credit risk is also inherent in CenterPoint Energy’s and CERC’s non-trading derivative activities. Credit risk relates to the risk of loss resulting from non-performance of contractual obligations by a counterparty. The following tables show the composition of counterparties to the non-trading derivative assets:

CenterPoint Energy

	December 31, 2019				December 31, 2018
	Investment Grade (1)		Total (3)		Investment Grade (1)		Total (3)
	(in millions)
Energy marketers	$	4	$	16	$	11	$	24
End users (2)	27		178		30		114
Total CenterPoint Energy	$	31	$	194	$	41	$	138

CERC

	December 31, 2019				December 31, 2018
	Investment Grade (1)		Total (3)		Investment Grade (1)		Total (3)
	(in millions)
Energy marketers	$	4	$	16	$	11	$	24
End users (2)	27		178		30		114
Total CERC	$	31	$	194	$	41	$	138

(1) “Investment grade” is primarily determined using publicly available credit ratings and considers credit support (including parent company guarantees) and collateral (including cash and standby letters of credit). For unrated counterparties, CERC determines a synthetic credit rating by performing financial statement analysis and consider contractual rights and restrictions and collateral.

(2) End users are comprised primarily of customers who have contracted to fix the price of a portion of their physical gas requirements for future periods.

(3)

The amounts reflected in the table above were not impacted by collateral netting.

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Equity (CenterPoint Energy) (Tables)

12 Months Ended

Dec. 31, 2019

Stockholders' Equity Note [Abstract]

Dividends Declared [Table Text Block]

CenterPoint Energy declared dividends on its Common Stock during 2019, 2018 and 2017 as presented in the table below:

Declaration Date	Record Date	Payment Date	Per Share		Total (in millions)
October 17, 2019	November 21, 2019	December 12, 2019	$	0.2875	$	144
July 31, 2019	August 15, 2019	September 12, 2019	0.2875		145
April 25, 2019	May 16, 2019	June 13, 2019	0.2875		144
Total 2019			$	0.8625	$	433
December 12, 2018	February 21, 2019	March 14, 2019	$	0.2875	$	144
October 23, 2018	November 15, 2018	December 13, 2018	0.2775		139
July 26, 2018	August 16, 2018	September 13, 2018	0.2775		120
April 26, 2018	May 17, 2018	June 14, 2018	0.2775		120
Total 2018			$	1.1200	$	523

Declaration Date	Record Date	Payment Date	Per Share		Total (in millions)
December 13, 2017	February 15, 2018	March 8, 2018	$	0.2775	$	120
October 25, 2017	November 16, 2017	December 8, 2017	0.2675		116
July 27, 2017	August 16, 2017	September 8, 2017	0.2675		115
April 27, 2017	May 16, 2017	June 9, 2017	0.2675		115
January 5, 2017	February 16, 2017	March 10, 2017	0.2675		115
Total 2017			$	1.3475	$	581

CenterPoint Energy declared dividends on its Series A Preferred Stock during 2019 and 2018 as presented in the table below:

Declaration Date	Record Date	Payment Date	Per Share		Total (in millions)
July 31, 2019	August 15, 2019	September 3, 2019	$	30.6250	$	24
Total 2019			$	30.6250	$	24
December 12, 2018	February 15, 2019	March 1, 2019	$	32.1563	$	26
Total 2018			$	32.1563	$	26

CenterPoint Energy declared dividends on its Series B Preferred Stock during 2019 and 2018 as presented in the table below:

Declaration Date	Record Date	Payment Date	Per Share		Total (in millions)
October 17, 2019	November 15, 2019	December 2, 2019	$	17.5000	$	17
July 31, 2019	August 15, 2019	September 3, 2019	17.5000		17
April 25, 2019	May 15, 2019	June 3, 2019	17.5000		17
Total 2019			$	52.5000	$	51
December 12, 2018	February 15, 2019	March 1, 2019	$	17.5000	$	17
October 23, 2018	November 15, 2018	December 1, 2018	11.6667		11
Total 2018			$	29.1667	$	28

There were no Series A Preferred Stock or Series B Preferred Stock outstanding or dividends declared in 2017.

Dividend Requirement on Preferred Stock

	Year Ended December 31,
	2019		2018		2017
	(in millions)
Series A Preferred Stock	$	49	$	18	$	—
Series B Preferred Stock	68		17		—
Total preferred stock dividend requirement	$	117	$	35	$	—

Convertible Debt [Table Text Block]

The following table illustrates the conversion rate per share of the Series B Preferred Stock, subject to certain anti-dilution adjustments:

Applicable Market Value of the Common Stock	Conversion Rate per Share of Series B Preferred Stock
Greater than $32.6990 (threshold appreciation price)	30.5820 shares of Common Stock
Equal to or less than $32.6990 but greater than or equal to $27.2494	Between 30.5820 and 36.6980 shares of Common Stock, determined by dividing $1,000 by the applicable market value
Less than $27.2494 (initial price)	36.6980 shares of Common Stock

The following table illustrates the conversion rate per depositary share, subject to certain anti-dilution adjustments:

Applicable Market Value of the Common Stock	Conversion Rate per Depository Share
Greater than $32.6990 (threshold appreciation price)	1.5291 shares of Common Stock
Equal to or less than $32.6990 but greater than or equal to $27.2494	Between 1.5291 and 1.8349 shares of Common Stock, determined by dividing $50 by the applicable market value
Less than $27.2494 (initial price)	1.8349 shares of Common Stock

Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block]

Amounts recognized in accumulated other comprehensive loss (gain) consist of the following:

	December 31,
	2019								2018
	Pension Benefits		Postretirement Benefits						Pension Benefits		Postretirement Benefits
	CenterPoint Energy		CenterPoint Energy			CERC			CenterPoint Energy		CenterPoint Energy			CERC
	(in millions)
Unrecognized actuarial loss (gain)	$	105	$	(16	)	$	(12	)	$	109	$	(7	)	$	(3	)
Unrecognized prior service cost	—		7			7			1		5			5
Deferred tax benefit	—		—			—			—		—			(9		)
Net amount recognized in accumulated other comprehensive loss (gain)	$	105	$	(9	)	$	(5	)	$	110	$	(2	)	$	(7	)

Changes in accumulated comprehensive income (loss) are as follows:

	Year Ended December 31,
	2019									2018
	CenterPoint Energy			Houston Electric			CERC			CenterPoint Energy			Houston Electric			CERC
	(in millions)
Beginning Balance	$	(108	)	$	(14	)	$	5		$	(68	)	$	—		$	6
Other comprehensive income (loss) before reclassifications:
Remeasurement of pension and other postretirement plans	7			—			7			(19		)	—			1
Deferred loss from interest rate derivatives (1)	(3		)	(1		)	—			(19		)	(18		)	(1		)
Reclassified to earnings	1			—			—			—			—			—
Other comprehensive loss from unconsolidated affiliates	(1		)	—			—			—			—			—
Amounts reclassified from accumulated other comprehensive loss:
Prior service cost (2)	1			—			—			1			—			1
Actuarial losses (2)	8			—			—			6			—			—
Tax benefit (expense)	(3		)	—			(2		)	6			4			(1		)
Net current period other comprehensive income (loss)	10			(1		)	5			(25		)	(14		)	—
Adoption of ASU 2018-02	—			—			—			(15		)	—			(1		)
Ending Balance	$	(98	)	$	(15	)	$	10		$	(108	)	$	(14	)	$	5

(1) Gains and losses are reclassified from Accumulated other comprehensive income into income when the hedged transactions affect earnings. The reclassification amounts are included in Interest and other finance charges in each of the Registrant’s respective Statements of Consolidated Income. Amounts are $1 million and less than $1 million for the years ended December 31, 2019 and 2018, respectively.

(2)

Amounts are included in the computation of net periodic cost and are reflected in Other, net in each of the Registrants’ respective Statements of Consolidated Income.

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STATEMENTS OF CONSOLIDATED SHAREHOLDERS' EQUITY - USD ($) $ in Millions	Total	Series A Preferred Stock [Member]	Series B Preferred Stock [Member]	Preferred Stock [Member]	Preferred Stock [Member] Series A Preferred Stock [Member]	Preferred Stock [Member] Series B Preferred Stock [Member]	Common Stock [Member]	Additional Paid-in Capital [Member]	Additional Paid-in Capital [Member] Common Stock [Member]	Retained Earnings [Member]	Retained Earnings [Member] Series A Preferred Stock [Member]	Retained Earnings [Member] Series B Preferred Stock [Member]	AOCI Attributable to Parent [Member]	Houston Electric [Member]	Houston Electric [Member] Common Stock [Member]	Houston Electric [Member] Additional Paid-in Capital [Member]	Houston Electric [Member] Retained Earnings [Member]	Houston Electric [Member] AOCI Attributable to Parent [Member]	CERC Corp [Member]		CERC Corp [Member] Common Stock [Member]	CERC Corp [Member] Additional Paid-in Capital [Member]	CERC Corp [Member] Retained Earnings [Member]	CERC Corp [Member] AOCI Attributable to Parent [Member]
Balance, beginning of year at Dec. 31, 2016				0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuances of stock					0	0	0
Balance, end of year at Dec. 31, 2017				0
Balance, beginning of year at Dec. 31, 2016							431,000,000								1,000						1,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuances related to benefit and investment plans							0
Balance, end of year at Dec. 31, 2017							431,000,000								1,000						1,000
Balance, beginning of year at Dec. 31, 2016				$ 0			$ 4	$ 4,195		$ (668)			$ (71)		$ 0	$ 1,696	$ 420	$ 1			$ 0	$ 2,489	$ 430	$ 3
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuances related to benefit and investment plans							0	14
Issuances of stock					$ 0	$ 0	0		$ 0
Contribution From Parent																0						38
Capital distribution associated with the Internal Spin	$ 0													$ 0					$ 0			0
Other																						1
Net income	1,792									1,792				433			433		745				745
Common Stock dividends declared ($0.8625, $1.1200 and $1.3475 per share, respectively)										(581)
Preferred stock dividends declared											$ 0	$ 0
Dividend to parent																	(180)						(601)
Other comprehensive income (loss)													3					(1)						3
Balance, end of year at Dec. 31, 2017	$ 4,688			$ 0			$ 4	4,209		543			(68)	2,369	$ 0	1,696	673	0	3,108		$ 0	2,528	574	6
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Adoption of ASU 2018-02 | Adjustments for New Accounting Principle, Early Adoption [Member]										0			0										0	0
Issuances of stock					1,000,000	1,000,000	70,000,000
Balance, end of year at Dec. 31, 2018		800,000	977,500	2,000,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuances related to benefit and investment plans							0
Balance, end of year at Dec. 31, 2018	501,197,784						501,000,000								1,000						1,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuances related to benefit and investment plans							$ 0	19
Issuances of stock					$ 790	$ 950	1		1,844
Contribution From Parent																200						960
Capital distribution associated with the Internal Spin	$ 0													0					(1,473)	[1]		1,473
Other																						0
Net income	368									368				336			336		208				208
Common Stock dividends declared ($0.8625, $1.1200 and $1.3475 per share, respectively)										(523)
Preferred stock dividends declared		$ (26)	$ (28)								(26)	(28)
Dividend to parent																	(209)						(360)
Other comprehensive income (loss)													(25)					(14)						0
Balance, end of year at Dec. 31, 2018	$ 8,058			$ 1,740			$ 5	6,072		349			(108)	2,682	$ 0	1,896	800	(14)	2,443		$ 0	2,015	423	5
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Adoption of ASU 2018-02 | Adjustments for New Accounting Principle, Early Adoption [Member]										15			(15)										1	(1)
Issuances of stock					0	0	0
Balance, end of year at Dec. 31, 2019		800,000	977,500	2,000,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuances related to benefit and investment plans							1,000,000
Balance, end of year at Dec. 31, 2019	502,242,061						502,000,000								1,000						1,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuances related to benefit and investment plans							$ 0	8
Issuances of stock					$ 0	$ 0	0		$ 0
Contribution From Parent																590						129
Capital distribution associated with the Internal Spin	$ 0													0					(28)	[1],[2]		28
Other																						0
Net income	791									791				356			356		212				212
Common Stock dividends declared ($0.8625, $1.1200 and $1.3475 per share, respectively)										(433)
Preferred stock dividends declared		$ (24)	$ (51)								$ (24)	$ (51)
Dividend to parent																	(376)						(120)
Other comprehensive income (loss)													10					(1)						5
Balance, end of year at Dec. 31, 2019	$ 8,359			$ 1,740			$ 5	$ 6,080		632			(98)	$ 3,251	$ 0	$ 2,486	$ 780	$ (15)	$ 2,641		$ 0	$ 2,116	515	10
Balance, end of year (Adjustments for New Accounting Principle, Early Adoption [Member]) at Dec. 31, 2019																								2,641
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Adoption of ASU 2018-02 | Adjustments for New Accounting Principle, Early Adoption [Member]										$ 0			$ 0										$ 0	$ 0

[1] The capital distribution in 2019 associated with the Internal Spin is a result of the return to accrual for the periods of CERC’s ownership during 2018.

[2] The capital distribution in 2019 associated with the Internal Spin is a result of the return to accrual for the periods of CERC’s ownership during 2018.

XML

Revenue Recognition Remaining Performance Obligations (Details) $ in Millions	Dec. 31, 2019 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 338
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	752
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	1,090
Infrastructure Services [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	254
Infrastructure Services [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	0
Infrastructure Services [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	254
Corporate and Other [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	84
Corporate and Other [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	752
Corporate and Other [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 836

XML

Property, Plant and Equipment (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019		Dec. 31, 2018	Dec. 31, 2017
Property, Plant and Equipment, Net, by Type [Abstract]
Property, Plant and Equipment, Gross		$ 30,685		$ 20,267
Accumulated Depreciation & Amortization		9,740		6,223
Property, Plant and Equipment, Net		20,945		14,044
Depreciation and Amortization [Abstract]
Depreciation		920		626	$ 619
Amortization of securitized regulatory assets		271		531	329
Other amortization		96		86	88
Total		1,287		1,243	1,036
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		258		281
Asset Retirement Obligation Addition from Merger with Vectren		116
Accretion expense (1)	[1]	16		10
Revisions in estimates (2)	[2]	149		(33)
Ending balance		539		258	281
Houston Electric [Member]
Property, Plant and Equipment, Net, by Type [Abstract]
Property, Plant and Equipment, Gross		12,829		12,148
Accumulated Depreciation & Amortization		3,797		3,746
Property, Plant and Equipment, Net		9,032		8,402
Depreciation and Amortization [Abstract]
Depreciation		339		342	354
Amortization of securitized regulatory assets		271		531	329
Other amortization		38		44	41
Total		648		917	724
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		34		35
Accretion expense (1)	[1]	1		1
Revisions in estimates (2)	[2]	7		(2)
Ending balance		42		34	35
CERC Corp [Member]
Property, Plant and Equipment, Net, by Type [Abstract]
Property, Plant and Equipment, Gross		8,124		7,431
Accumulated Depreciation & Amortization		2,288		2,205
Property, Plant and Equipment, Net		5,836		5,226
Depreciation and Amortization [Abstract]
Depreciation		281		264	243
Other amortization		24		29	36
Total		305		293	279
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		221		243
Accretion expense (1)	[1]	10		9
Revisions in estimates (2)	[2]	94		(31)
Ending balance		325		221	$ 243
Electric Transmission and Distribution [Member]
Property, Plant and Equipment, Net, by Type [Abstract]
Property, Plant and Equipment, Gross		14,360		12,148
Accumulated Depreciation & Amortization		4,634		3,746
Property, Plant and Equipment, Net		$ 9,726		8,402
Electric Transmission and Distribution [Member] | Weighted Average [Member]
Property, Plant and Equipment, Net, by Type [Abstract]
Weighted Average Useful Lives		37 years
Electric Generation Equipment [Member]
Property, Plant and Equipment, Net, by Type [Abstract]
Property, Plant and Equipment, Gross		$ 1,780	[3]	0
Accumulated Depreciation & Amortization		698	[3]	0
Property, Plant and Equipment, Net		$ 1,082	[3]	0
Electric Generation Equipment [Member] | Weighted Average [Member]
Property, Plant and Equipment, Net, by Type [Abstract]
Weighted Average Useful Lives		27 years
Electric Transmission [Member] | Houston Electric [Member]
Property, Plant and Equipment, Net, by Type [Abstract]
Property, Plant and Equipment, Gross		$ 3,358		3,077
Accumulated Depreciation & Amortization		674		650
Property, Plant and Equipment, Net		$ 2,684		2,427
Electric Transmission [Member] | Houston Electric [Member] | Weighted Average [Member]
Property, Plant and Equipment, Net, by Type [Abstract]
Weighted Average Useful Lives		46 years
Electric Distribution [Member] | Houston Electric [Member]
Property, Plant and Equipment, Net, by Type [Abstract]
Property, Plant and Equipment, Gross		$ 7,876		7,524
Accumulated Depreciation & Amortization		2,586		2,553
Property, Plant and Equipment, Net		$ 5,290		4,971
Electric Distribution [Member] | Houston Electric [Member] | Weighted Average [Member]
Property, Plant and Equipment, Net, by Type [Abstract]
Weighted Average Useful Lives		35 years
Natural Gas Distribution [Member]
Property, Plant and Equipment, Net, by Type [Abstract]
Property, Plant and Equipment, Gross		$ 12,695		7,257
Accumulated Depreciation & Amortization		3,731		2,128
Property, Plant and Equipment, Net		$ 8,964		5,129
Natural Gas Distribution [Member] | Weighted Average [Member]
Property, Plant and Equipment, Net, by Type [Abstract]
Weighted Average Useful Lives		29 years
Natural Gas Distribution [Member] | CERC Corp [Member]
Property, Plant and Equipment, Net, by Type [Abstract]
Property, Plant and Equipment, Gross		$ 7,933		7,257
Accumulated Depreciation & Amortization		2,208		2,128
Property, Plant and Equipment, Net		$ 5,725		5,129
Natural Gas Distribution [Member] | CERC Corp [Member] | Weighted Average [Member]
Property, Plant and Equipment, Net, by Type [Abstract]
Weighted Average Useful Lives		29 years
Energy Services [Member]
Property, Plant and Equipment, Net, by Type [Abstract]
Property, Plant and Equipment, Gross		$ 136	[4]	121
Accumulated Depreciation & Amortization		53	[4]	43
Property, Plant and Equipment, Net		$ 83	[4]	78
Energy Services [Member] | Weighted Average [Member]
Property, Plant and Equipment, Net, by Type [Abstract]
Weighted Average Useful Lives		27 years
Energy Services [Member] | CERC Corp [Member]
Property, Plant and Equipment, Net, by Type [Abstract]
Property, Plant and Equipment, Gross		$ 136	[4]	121
Accumulated Depreciation & Amortization		53	[4]	43
Property, Plant and Equipment, Net		$ 83	[4]	78
Energy Services [Member] | CERC Corp [Member] | Weighted Average [Member]
Property, Plant and Equipment, Net, by Type [Abstract]
Weighted Average Useful Lives		27 years
Infrastructure Services [Member]
Property, Plant and Equipment, Net, by Type [Abstract]
Property, Plant and Equipment, Gross		$ 317	[5]	0
Accumulated Depreciation & Amortization		22	[5]	0
Property, Plant and Equipment, Net		$ 295	[5]	0
Infrastructure Services [Member] | Weighted Average [Member]
Property, Plant and Equipment, Net, by Type [Abstract]
Weighted Average Useful Lives		10 years
Other property [Member]
Property, Plant and Equipment, Net, by Type [Abstract]
Property, Plant and Equipment, Gross		$ 1,397		741
Accumulated Depreciation & Amortization		602		306
Property, Plant and Equipment, Net		$ 795		435
Other property [Member] | Weighted Average [Member]
Property, Plant and Equipment, Net, by Type [Abstract]
Weighted Average Useful Lives		19 years
Other property [Member] | Houston Electric [Member]
Property, Plant and Equipment, Net, by Type [Abstract]
Property, Plant and Equipment, Gross		$ 1,595		1,547
Accumulated Depreciation & Amortization		537		543
Property, Plant and Equipment, Net		$ 1,058		1,004
Other property [Member] | Houston Electric [Member] | Weighted Average [Member]
Property, Plant and Equipment, Net, by Type [Abstract]
Weighted Average Useful Lives		19 years
Other property [Member] | CERC Corp [Member]
Property, Plant and Equipment, Net, by Type [Abstract]
Property, Plant and Equipment, Gross		$ 55		53
Accumulated Depreciation & Amortization		27		34
Property, Plant and Equipment, Net		$ 28		$ 19
Other property [Member] | CERC Corp [Member] | Weighted Average [Member]
Property, Plant and Equipment, Net, by Type [Abstract]
Weighted Average Useful Lives		16 years
SIGECO [Member]
Property, Plant and Equipment, Net, by Type [Abstract]
SIGECO's share of cost of Warrick Unit 4		$ 194
SIGECO's share of accumulated depreciation of Warrick Unit 4		$ 137

[1] Reflected in Regulatory assets on each of the Registrants’ respective Consolidated Balance Sheets.

[2] In 2019, the Registrants reflected an increase in their respective ARO liability, which is primarily attributable to decreases in the long-term interest rates used for discounting in the ARO calculation and increased estimated closure costs for CenterPoint Energy’s electric generation. In 2018, CenterPoint Energy and CERC reflected a decrease in their respective ARO liability, which is primarily attributable to increases in the long-term interest rates used for discounting in the ARO calculation.

[3] SIGECO and AGC own a 300 MW unit at the Warrick Power Plant (Warrick Unit 4) as tenants in common. SIGECO’s share of the cost of this unit as of December 31, 2019, is $194 million with accumulated depreciation totaling $137 million. AGC and SIGECO share equally in the cost of operation and output of the unit. SIGECO’s share of operating costs is included in Operation and maintenance expense in CenterPoint Energy’s Statements of Consolidated Income.

[4] 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. The transaction is expected to close in the second quarter of 2020. For further information, see Notes 6 and 23.

[5] 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 is expected to close in the second quarter of 2020. For further information, see Notes 6 and 23.

XML

Leases (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019	Jan. 01, 2019	Dec. 31, 2018
Lease, Cost [Abstract]
Operating lease cost		$ 25
Short-term lease cost		75
Variable lease cost		1
Total lease cost		101
Operating Leases, Lease Income [Abstract]
Operating lease income		4
Variable lease income		2
Total lease income		6
Assets and Liabilities, Lessee [Abstract]
Operating ROU assets (1)	[1]	63
Total leased assets		63	$ 30
Current operating lease liability (2)	[2]	21
Non-current operating lease liability (3)	[3]	42
Total leased liabilities		$ 63
Weighted-average remaining lease term (in years) - operating leases		5 years 1 month 6 days
Weighted-average discount rate - operating leases		3.42%
Operating Lease Liabilities, Payments Due [Abstract]
2020		$ 22
2021		16
2022		9
2023		7
2024		3
2025 and beyond		12
Total lease payments		69
Less: Interest		6
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
2019	[4]			$ 6
2020	[4]			6
2021	[4]			5
2022	[4]			4
2023	[4]			3
2024 and beyond	[4]			12
Total (1)	[4]			36
Lessor, Operating Lease, Payments, Fiscal Year Maturity [Abstract]
2020		3
2021		2
2022		2
2023		2
2024		2
2025 and beyond		10
Total lease payments to be received		21
Other Information Related to Leases [Abstract]
Operating cash flows from operating leases included in the measurement of lease liabilities		25
Lessee Operating Lease Not Yet Commenced		16
Houston Electric [Member]
Lease, Cost [Abstract]
Operating lease cost		0
Short-term lease cost		23
Variable lease cost		0
Total lease cost		23
Operating Leases, Lease Income [Abstract]
Operating lease income		2
Variable lease income		0
Total lease income		2
Assets and Liabilities, Lessee [Abstract]
Operating ROU assets (1)	[1]	1
Total leased assets		1	1
Current operating lease liability (2)	[2]	0
Non-current operating lease liability (3)	[3]	1
Total leased liabilities		$ 1
Weighted-average remaining lease term (in years) - operating leases		5 years 2 months 12 days
Weighted-average discount rate - operating leases		3.52%
Operating Lease Liabilities, Payments Due [Abstract]
2020		$ 1
2021		0
2022		0
2023		0
2024		0
2025 and beyond		0
Total lease payments		1
Less: Interest		0
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
2019				1
2020				0
2021				0
2022				0
2023				0
2024 and beyond				0
Total (1)				1
Lessor, Operating Lease, Payments, Fiscal Year Maturity [Abstract]
2020		1
2021		0
2022		0
2023		0
2024		0
2025 and beyond		0
Total lease payments to be received		1
Other Information Related to Leases [Abstract]
Operating cash flows from operating leases included in the measurement of lease liabilities		1
CERC Corp [Member]
Lease, Cost [Abstract]
Operating lease cost		5
Short-term lease cost		0
Variable lease cost		1
Total lease cost		6
Operating Leases, Lease Income [Abstract]
Operating lease income		1
Variable lease income		0
Total lease income		1
Assets and Liabilities, Lessee [Abstract]
Operating ROU assets (1)	[1]	24
Total leased assets		24	$ 27
Current operating lease liability (2)	[2]	4
Non-current operating lease liability (3)	[3]	20
Total leased liabilities		$ 24
Weighted-average remaining lease term (in years) - operating leases		7 years 8 months 12 days
Weighted-average discount rate - operating leases		3.67%
Operating Lease Liabilities, Payments Due [Abstract]
2020		$ 6
2021		4
2022		4
2023		3
2024		2
2025 and beyond		9
Total lease payments		28
Less: Interest		4
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
2019				5
2020				5
2021				4
2022				4
2023				3
2024 and beyond				11
Total (1)				$ 32
Lessor, Operating Lease, Payments, Fiscal Year Maturity [Abstract]
2020		1
2021		0
2022		0
2023		0
2024		0
2025 and beyond		0
Total lease payments to be received		1
Other Information Related to Leases [Abstract]
Operating cash flows from operating leases included in the measurement of lease liabilities		$ 6

[1] Reported within Other assets in the Registrants’ respective Consolidated Balance Sheets.

[2] Reported within Current other liabilities in the Registrants’ respective Consolidated Balance Sheets.

[3] Reported within Other liabilities in the Registrants’ respective Consolidated Balance Sheets.

[4] The Merger was completed on February 1, 2019. As such, these amounts are exclusive of Vectren’s leases.

XML

Stock-Based Incentive Compensation Plans and Employee Benefit Plans Stock Based Incentive Compensation (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions		12 Months Ended
		Dec. 31, 2019		Dec. 31, 2018	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares authorized for issuance under long-term incentive plans (in shares)		14,000
Employee Service Share-based Compensation, Aggregate Disclosures [Abstract]
Income tax benefit recognized related to LTIPs		$ 7		$ 6	$ 8
Actual tax benefit realized for tax deductions		$ 12		$ 5	$ 6
Performance Awards [Member]
Summary of nonvested shares [Roll Forward]
Nonvested, beginning of period (in shares)	[1]	3,818
Granted (in shares)	[1]	1,413
Forfeited or cancelled (in shares)	[1]	(825)
Vested and released to participants (in shares)	[1]	(1,074)
Nonvested, end of period (in shares)	[1]	3,332		3,818
Weighted average grant date fair value, nonvested, beginning of period (in dollars per share)	[1]	$ 23.91
Weighted average grant date fair values of awards granted (in dollars per share)		31.16	[1]	$ 26.74	$ 26.64
Weighted average grant date fair value, forfeited or cancelled (in dollars per share)	[1]	24.78
Weighted average grant date fair value, vested and released to participants (in dollars per share)	[1]	18.97
Weighted average grant date fair value, nonvested, end of period (in dollars per share)	[1]	$ 28.36		$ 23.91
Remaining average contractual life of nonvested shares outstanding (in years)		1 year 1 month 6 days
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Aggregate Intrinsic Value, Nonvested	[1],[2]	$ 53
Total intrinsic value of awards received by participants		36		$ 12	$ 7
Total grant date fair values of performance and stock awards which vested during the period		$ 20		$ 9	$ 5
Stock Awards [Member]
Summary of nonvested shares [Roll Forward]
Nonvested, beginning of period (in shares)		1,060
Granted (in shares)		470
Forfeited or cancelled (in shares)		(131)
Vested and released to participants (in shares)		(433)
Nonvested, end of period (in shares)		966		1,060
Weighted average grant date fair value, nonvested, beginning of period (in dollars per share)		$ 24.08
Weighted average grant date fair values of awards granted (in dollars per share)		31.07		$ 26.62	$ 26.77
Weighted average grant date fair value, forfeited or cancelled (in dollars per share)		27.95
Weighted average grant date fair value, vested and released to participants (in dollars per share)		20.72
Weighted average grant date fair value, nonvested, end of period (in dollars per share)		$ 28.46		$ 24.08
Remaining average contractual life of nonvested shares outstanding (in years)		1 year 2 months 12 days
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Aggregate Intrinsic Value, Nonvested	[2]	$ 26
Total intrinsic value of awards received by participants		15		$ 9	$ 9
Total grant date fair values of performance and stock awards which vested during the period		9		7	7
Performance and Stock Awards [Member]
Summary of nonvested shares [Roll Forward]
Unrecognized compensation cost related to non-vested performance and stock awards		$ 34
Weighted average period of recognition (in years)		1 year 8 months 12 days
Operation And Maintenance Expense [Member]
Employee Service Share-based Compensation, Aggregate Disclosures [Abstract]
LTIP compensation expense	[3]	$ 28		$ 26	$ 21

[1] Reflects maximum performance achievement.

[2] Reflects the impact of current expectations of achievement and stock price.

[3] Amounts presented in the table above are included in Operation and maintenance expense in CenterPoint Energy’s Statements of Consolidated Income and shown prior to any amounts capitalized.

XML

STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Tax benefit (expense) on adjustment related to pension and postretirement plans	$ (4)	$ 2	$ (6)
Tax expense (benefit) on net deferred gain (loss) from cash flow hedges	(1)	(4)	(2)
Tax expense (benefit) on deferred loss from cash flow hedges realized in net income	0	0	0
Houston Electric [Member]
Tax expense (benefit) on net deferred gain (loss) from cash flow hedges	0	(4)	0
CERC Corp [Member]
Tax benefit (expense) on adjustment related to pension and postretirement plans	(2)	(1)	(4)
Tax expense (benefit) on net deferred gain (loss) from cash flow hedges	$ 0	$ 0	$ (1)

XML

Cover Page - USD ($)	12 Months Ended
	Dec. 31, 2019	Feb. 19, 2020	Jun. 30, 2019
Entity Information [Line Items]
Document Type	10-K
Document Annual Report	true
Document Transition Report	false
Entity File Number	1-31447
Entity Registrant Name	CenterPoint Energy, Inc.
Entity Tax Identification Number	74-0694415
Entity Incorporation, State or Country Code	TX
Entity Address, Address Line One	1111 Louisiana
Entity Address, City or Town	Houston,
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77002
City Area Code	(713)
Local Phone Number	207-1111
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Public Float			$ 14,295,717,409
Entity Common Stock, Shares Outstanding		502,243,185
Entity Central Index Key	0001130310
Current Fiscal Year End Date	--12-31
Document Period End Date	Dec. 31, 2019
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	FY
Amendment Flag	false
Common Stock, $0.01 par value | New York Stock Exchange
Entity Information [Line Items]
Title of 12(b) Security	Common Stock, $0.01 par value
Trading Symbol	CNP
Security Exchange Name	NYSE
Common Stock, $0.01 par value | Chicago Stock Exchange
Entity Information [Line Items]
Title of 12(b) Security	Common Stock, $0.01 par value
Trading Symbol	CNP
Security Exchange Name	CHX
Depositary shares, each representing a 1/20th interest in a share of 7.00% Series B Mandatory Convertible Preferred Stock, $0.01 par value | New York Stock Exchange
Entity Information [Line Items]
Title of 12(b) Security	Depositary shares, each representing a 1/20th interest in a share of 7.00% Series B Mandatory Convertible Preferred Stock, $0.01 par value
Trading Symbol	CNP/PB
Security Exchange Name	NYSE
CenterPoint Energy Houston Electric, LLC
Entity Information [Line Items]
Entity File Number	1-3187
Entity Registrant Name	CenterPoint Energy Houston Electric, LLC
Entity Tax Identification Number	22-3865106
Entity Incorporation, State or Country Code	TX
Entity Address, Address Line One	1111 Louisiana
Entity Address, City or Town	Houston,
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77002
City Area Code	(713)
Local Phone Number	207-1111
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Public Float			0
Entity Common Stock, Shares Outstanding		1,000
Entity Central Index Key	0000048732
CenterPoint Energy Houston Electric, LLC | 9.15% First Mortgage Bonds due 2021 | New York Stock Exchange
Entity Information [Line Items]
Title of 12(b) Security	9.15% First Mortgage Bonds due 2021
Trading Symbol	n/a
Security Exchange Name	NYSE
CenterPoint Energy Houston Electric, LLC | 6.95% General Mortgage Bonds due 2033 | New York Stock Exchange
Entity Information [Line Items]
Title of 12(b) Security	6.95% General Mortgage Bonds due 2033
Trading Symbol	n/a
Security Exchange Name	NYSE
CenterPoint Energy Resources Corp.
Entity Information [Line Items]
Entity File Number	1-13265
Entity Registrant Name	CenterPoint Energy Resources Corp.
Entity Tax Identification Number	76-0511406
Entity Incorporation, State or Country Code	DE
Entity Address, Address Line One	1111 Louisiana
Entity Address, City or Town	Houston,
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77002
City Area Code	(713)
Local Phone Number	207-1111
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Public Float			$ 0
Entity Common Stock, Shares Outstanding		1,000
Entity Central Index Key	0001042773
CenterPoint Energy Resources Corp. | 6.625% Senior Notes due 2037 | New York Stock Exchange
Entity Information [Line Items]
Title of 12(b) Security	6.625% Senior Notes due 2037
Trading Symbol	n/a
Security Exchange Name	NYSE

XML

Commitments and Contingencies

12 Months Ended

Dec. 31, 2019

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies [Text Block]

Commitments and Contingencies

(a) Purchase Obligations (CenterPoint Energy and CERC)

Commitments include minimum purchase obligations related to CenterPoint Energy’s and CERC’s Natural Gas Distribution and Energy Services reportable segments and CenterPoint Energy’s Indiana Electric Integrated reportable segment. Contracts with minimum payment provisions have various quantity requirements and durations and are not classified as non-trading derivative assets and liabilities in CenterPoint Energy’s and CERC’s Consolidated Balance Sheets as of December 31, 2019 and 2018. These contracts meet an exception as “normal purchases contracts” or do not meet the definition of a derivative. Natural gas and coal supply commitments also include transportation contracts that do not meet the definition of a derivative.

As of December 31, 2019, minimum purchase obligations are approximately:

	CenterPoint Energy		CERC
	(in millions)
2020	$	750	$	533
2021	617		432
2022	418		242
2023	335		182
2024	271		174
2025 and beyond	1,888		1,526

Indiana Electric also has other purchased power agreements that do not have minimum thresholds but do require payment when energy is generated by the provider. Costs arising from certain of these commitments are pass-through costs, generally collected dollar-for-dollar from retail customers through regulator-approved cost recovery mechanisms.

(b) AMAs (CenterPoint Energy and CERC)

CenterPoint Energy’s and CERC’s NGD has AMAs associated with their utility distribution service in Arkansas, Indiana, Louisiana, Mississippi, Oklahoma and Texas. The AMAs have varying terms, the longest of which expires in 2023. Pursuant to the provisions of the agreements, CenterPoint Energy’s and CERC’s NGD 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 NGD 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 NGD 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 NGD and to use the released capacity for other purposes when it is not needed for CenterPoint Energy’s and CERC’s NGD. CenterPoint Energy’s and CERC’s NGD may receive compensation from the asset manager through payments made over the life of the AMAs. CenterPoint Energy’s and CERC’s NGD has an obligation to purchase their winter storage requirements that have been released to the asset manager under these AMAs.

(c) Guarantees and Product Warranties (CenterPoint Energy)

In the normal course of business, ESG enters into contracts requiring it to timely install infrastructure, operate facilities, pay vendors and subcontractors and support warranty obligations and, at times, issue payment and performance bonds and other forms of assurance in connection with these contracts.

Specific to ESG’s role as a general contractor in the performance contracting industry, as of December 31, 2019, there were 62 open surety bonds supporting future performance with an aggregate face amount of approximately $565 million. ESG’s exposure is less than the face amount of the surety bonds and is limited to the level of uncompleted work under the contracts. As of December 31, 2019, approximately 36% of the work was yet to be completed on projects with open surety bonds. Further, various subcontractors issue surety bonds to ESG. In addition to these performance obligations, ESG also warrants the functionality of certain installed infrastructure generally for one year and the associated energy savings over a specified number of years. Since ESG’s inception in 1994, CenterPoint Energy believes ESG has had a history of generally meeting its performance obligations and energy savings guarantees and its installed products operating effectively. CenterPoint Energy assessed the fair value of its obligation for such guarantees as of December 31, 2019 and no amounts were recorded on CenterPoint Energy’s Consolidated Balance Sheets.

CenterPoint Energy issues parent company level guarantees to certain vendors, customers and other commercial counterparties of ESG. These guarantees do not represent incremental consolidated obligations, but rather, represent guarantees of subsidiary obligations to allow those subsidiaries to conduct business without posting other forms of assurance. As of December 31, 2019, CenterPoint Energy, primarily through Vectren, has issued parent company level guarantees supporting ESG’s obligations. For those obligations where potential exposure can be estimated, management estimates the maximum exposure under these guarantees to be approximately $499 million as of December 31, 2019. This exposure primarily relates to energy savings guarantees on federal energy savings performance contracts. Other parent company level guarantees, certain of which do not contain a cap on potential liability, have been issued in support of federal operations and maintenance projects for which a maximum exposure cannot be estimated based on the nature of the projects. While there can be no assurance that performance under any of these parent company

guarantees will not be required in the future, CenterPoint Energy considers the likelihood of a material amount being incurred as remote.

(d) Guarantees and Product Warranties (CenterPoint Energy and CERC)

In the normal course of business, CES trades natural gas under supply contracts and enters into natural gas related transactions under transportation, storage and other contracts. In connection with these CES business activities, CERC Corp. has issued guarantees to CES counterparties to guarantee the payment of CES obligations. While CES remains wholly-owned by CERC Corp., these guarantees do not represent incremental consolidated obligations, but rather, represent guarantees of CES’s obligations to allow CES to conduct business without posting other forms of assurance. As of December 31, 2019, the face amount of CERC Corp.’s guarantees of CES obligations was approximately $1.8 billion.

A CERC Corp. guarantee primarily has a one- or two-year term, although CERC Corp. would generally not be released from obligations incurred by CES prior to the termination of such guarantee unless the beneficiary of the guarantee affirmatively released CERC Corp. from its obligations under the guarantee. Since CERC Corp. has owned CES, CERC Corp. has not paid any amounts under any guarantees of CES obligations. While there can be no assurance that performance under any of these parent company guarantees will not be required in the future, CenterPoint Energy and CERC consider the likelihood of a material amount being incurred as remote.

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. Under the terms of the Equity Purchase Agreement, Athena Energy Services must generally use reasonable best efforts to replace existing CERC Corp. guarantees with credit support provided by a party other than CERC Corp. as of and after closing of the sale. Additionally, to the extent that CERC Corp. retains any exposure relating to the guarantees of CES obligations 90 days after closing, Athena Energy Services will pay a 3% annualized fee on such exposure, increasing by 1% on an annualized basis every three months.

CenterPoint Energy and CERC recorded no amounts on their respective Consolidated Balance Sheets as of December 31, 2019 and 2018 related to these guarantees.

(e) Legal, Environmental and Other Matters

Legal Matters

Gas Market Manipulation Cases (CenterPoint Energy and CERC). CenterPoint Energy, its predecessor, Reliant Energy, and certain of their former subsidiaries were named as defendants in a large number of lawsuits filed against numerous gas market participants in a number of federal and western state courts in connection with the operation of the natural gas markets in 2000-2002. CenterPoint Energy and its affiliates were released or dismissed from all such cases, except for one case in federal court in Nevada in which CES, a subsidiary of CERC, was a defendant. Plaintiffs in that case alleged a conspiracy to inflate Wisconsin natural gas prices in 2000-2002. In October 2018, CES reached an agreement to settle all claims against CES and CES’s claims for indemnity. During the third quarter of 2019, the federal district court issued final approval of the settlement and dismissed the case, and CES completed the required settlement payments; the settlement agreement has now become final. This settlement did not have a material adverse effect on CenterPoint Energy’s or CERC’s financial condition, results of operations or cash flows.

Minnehaha Academy (CenterPoint Energy and CERC). On August 2, 2017, a natural gas explosion occurred at the Minnehaha Academy in Minneapolis, Minnesota, resulting in the deaths of two school employees, serious injuries to others and significant property damage to the school. CenterPoint Energy, certain of its subsidiaries, including CERC, and the contractor company working in the school have been named in litigation arising out of this incident. CenterPoint Energy and CERC have reached confidential settlement agreements on all wrongful death and property damage claims and with some personal injury claimants. Additionally, CenterPoint Energy and CERC cooperated with the investigation conducted by the National Transportation Safety Board, which concluded its investigation in December 2019 and issued a report without making any recommendations. Further, CenterPoint Energy and CERC contested and reached a settlement regarding approximately $200,000 in fines imposed by the Minnesota Office of Pipeline Safety.  In early 2018, the Minnesota Occupational Safety and Health Administration concluded its investigation without any adverse findings against CenterPoint Energy or CERC. CenterPoint Energy’s and CERC’s general and excess liability insurance policies provide coverage for third party bodily injury and property damage claims. 

Litigation Related to the Merger (CenterPoint Energy). With respect to the Merger, in July 2018, seven separate lawsuits were filed against Vectren and the individual directors of Vectren’s Board of Directors in the U.S. District Court for the Southern District of Indiana. These lawsuits alleged violations of Sections 14(a) of the Exchange Act and SEC Rule 14a-9 on the grounds that the Vectren Proxy Statement filed on June 18, 2018 was materially incomplete because it omitted material information concerning the Merger. In August 2018, the seven lawsuits were consolidated, and the Court denied the plaintiffs’ request for a preliminary

injunction. In October 2018, the plaintiffs filed their Consolidated Amended Class Action Complaint. In December 2018, two plaintiffs voluntarily dismissed their lawsuits. In September 2019, the court granted the defendants’ motion to dismiss and dismissed the remaining plaintiffs’ claims with prejudice, which the plaintiffs appealed in October 2019. The defendants believe that the allegations asserted are without merit and intend to vigorously defend themselves against the claims raised. CenterPoint Energy does not expect the ultimate outcome of this matter to have a material adverse effect on its financial condition, results of operations or cash flows.

Environmental Matters

MGP Sites. CenterPoint Energy, CERC and their predecessors operated MGPs in the past. In addition, certain of CenterPoint Energy’s subsidiaries acquired through the Merger operated MGPs in the past. The costs CenterPoint Energy or CERC, as applicable, expect to incur to fulfill their respective obligations are estimated by management using assumptions based on actual costs incurred, the timing of expected future payments and inflation factors, among others. While CenterPoint Energy and CERC have recorded all costs which they presently are obligated to incur in connection with activities at these sites, it is possible that future events may require remedial activities which are not presently foreseen, and those costs may not be subject to PRP or insurance recovery.

(i) Minnesota MGPs (CenterPoint Energy and CERC). With respect to certain Minnesota MGP sites, CenterPoint Energy and CERC have completed state-ordered remediation and continue state-ordered monitoring and water treatment. CenterPoint Energy and CERC recorded a liability as reflected in the table below for continued monitoring and any future remediation required by regulators in Minnesota.

(ii) Indiana MGPs (CenterPoint Energy). In the Indiana Gas service territory, the existence, location and certain general characteristics of 26 gas manufacturing and storage sites have been identified for which CenterPoint Energy may have some remedial responsibility. A remedial investigation/feasibility study was completed at one of the sites under an agreed upon order between Indiana Gas and the IDEM, and a Record of Decision was issued by the IDEM in January 2000. The remaining sites have been submitted to the IDEM’s VRP. CenterPoint Energy has also identified its involvement in five manufactured gas plant sites in SIGECO’s service territory, all of which are currently enrolled in the IDEM’s VRP. CenterPoint Energy is currently conducting some level of remedial activities, including groundwater monitoring at certain sites.

(iii) Other MGPs (CenterPoint Energy and CERC). In addition to the Minnesota and Indiana sites, the EPA and other regulators have investigated MGP sites that were owned or operated by CenterPoint Energy or CERC or may have been owned by one of their former affiliates.

Total costs that may be incurred in connection with addressing these sites cannot be determined at this time. The estimated accrued costs are limited to CenterPoint Energy’s and CERC’s share of the remediation efforts and are therefore net of exposures of other PRPs. The estimated range of possible remediation costs for the sites for which CenterPoint Energy and CERC believe they may have responsibility was based on remediation continuing for the minimum time frame given in the table below.

	December 31, 2019
	CenterPoint Energy		CERC
	(in millions, except years)
Amount accrued for remediation	$	12	$	7
Minimum estimated remediation costs	7		4
Maximum estimated remediation costs	51		32
Minimum years of remediation	5		30
Maximum years of remediation	50		50

The cost estimates are based on studies of a site or industry average costs for remediation of sites of similar size. The actual remediation costs will depend on the number of sites to be remediated, the participation of other PRPs, if any, and the remediation methods used.

CenterPoint Energy and CERC do not expect the ultimate outcome of these matters to have a material adverse effect on the financial condition, results of operations or cash flows of either CenterPoint Energy or CERC.

Asbestos. Some facilities owned by the Registrants or their predecessors contain or have contained asbestos insulation and other asbestos-containing materials. The Registrants are from time to time named, along with numerous others, as defendants in

lawsuits filed by a number of individuals who claim injury due to exposure to asbestos, and the Registrants anticipate that additional claims may be asserted in the future. Although their ultimate outcome cannot be predicted at this time, the Registrants do not expect these matters, either individually or in the aggregate, to have a material adverse effect on their financial condition, results of operations or cash flows.

CCR Rule (CenterPoint Energy). In April 2015, the EPA finalized its CCR Rule, which regulates ash as non-hazardous material under the RCRA. The final rule allows beneficial reuse of ash, and the majority of the ash generated by Indiana Electric’s generating plants will continue to be reused. In July 2018, the EPA released its final CCR Rule Phase I Reconsideration which extended the deadline to October 31, 2020 for ceasing placement of ash in ponds that exceed groundwater protections standards or that fail to meet location restrictions. While the EPA Phase I Reconsideration moves forward, the existing CCR compliance obligations remain in effect. In August 2019, the EPA proposed additional amendments to its CCR Rule with respect to beneficial reuse of ash and other materials. The proposed revisions would not restrict Indiana Electric’s current beneficial reuse of its fly ash.

Indiana Electric has three ash ponds, two at the F.B. Culley facility (Culley East and Culley West) and one at the A.B. Brown facility. Under the existing CCR Rule, Indiana Electric is required to perform integrity assessments, including ground water monitoring, at its F.B. Culley and A.B. Brown generating stations. The ground water studies are necessary to determine the remaining service life of the ponds and whether a pond must be retrofitted with liners or closed in place, with bottom ash handling conversions completed. Indiana Electric’s Warrick generating unit is not included in the scope of the CCR Rule as this unit has historically been part of a larger generating station that predominantly serves an adjacent industrial facility. In March 2018, Indiana Electric began posting ground water data monitoring reports annually to its public website in accordance with the requirements of the CCR Rule. This data preliminarily 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 October 31, 2020. CenterPoint Energy plans to seek extensions available under the CCR Rule that would allow Indiana Electric to continue to use the ponds through December 31, 2023. The inability to take these extensions may result in increased and potentially significant operational costs in connection with the accelerated implementation of an alternative ash disposal system or adversely impact Indiana Electric’s future operations. Failure to comply with these requirements could also result in an enforcement proceeding including the imposition of fines and penalties. On April 24, 2019, Indiana Electric received an order from the IURC approving recovery in rates of costs associated with the closure of the Culley West pond, which has already commenced closure activities. CenterPoint Energy believes the language in the IURC order is favorable for future recovery of closure costs for Indiana Electric’s remaining ponds.

Indiana Electric continues to refine site specific estimates of closure costs. In July 2018, Indiana Electric filed a Complaint for Damages and Declaratory Relief against its insurers seeking reimbursement of defense, investigation and pond closure costs incurred to comply with the CCR Rule, and has since reached confidential settlement agreements with its insurers. The proceeds of these settlements will offset costs that have been and will be incurred to close the ponds. In March 2019, Indiana Electric entered into agreements with third parties for the excavation and beneficial reuse of the ash at the A.B. Brown ash pond. On August 14, 2019, Indiana Electric filed its petition with the IURC for recovery of costs associated with the closure of the A.B. Brown ash pond, which would include costs associated with the excavation and recycling of the ponded ash. On November 4, 2019, the EPA released a pre-publication copy of proposed revisions to the CCR Rule. CenterPoint Energy will evaluate the proposals to determine potential impacts to current compliance plans for its A.B. Brown and F.B. Culley generating stations.

As of December 31, 2019, CenterPoint Energy has recorded an approximate $68 million ARO, which represents the discounted value of future cash flow estimates to close the ponds at A.B. Brown and F.B. Culley. This estimate is subject to change due to the contractual arrangements; continued assessments of the ash, closure methods, and the timing of closure; implications of Indiana Electric’s generation transition plan; changing environmental regulations; and proceeds received from the settlements in the aforementioned insurance proceeding. In addition to these removal costs, Indiana Electric also anticipates equipment purchases of between $60 million and $80 million to complete the A.B. Brown closure project.

Other Environmental. From time to time, the Registrants identify the presence of environmental contaminants during operations or on property where predecessors have conducted operations. Other such sites involving contaminants may be identified in the future. The Registrants have and expect to continue to remediate any identified sites consistent with state and federal legal obligations. From time to time, the Registrants have received notices, and may receive notices in the future, from regulatory authorities or others regarding status as a PRP in connection with sites found to require remediation due to the presence of environmental contaminants. In addition, the Registrants have been, or may be, named from time to time as defendants in litigation related to such sites. Although the ultimate outcome of such matters cannot be predicted at this time, the Registrants do not expect these matters, either individually or in the aggregate, to have a material adverse effect on their financial condition, results of operations or cash flows.

Other Proceedings

The Registrants are involved in other legal, environmental, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business. From time to time, the Registrants are also defendants in legal proceedings with respect to claims brought by various plaintiffs against broad groups of participants in the energy industry. Some of these proceedings involve substantial amounts. The Registrants regularly analyze current information and, as necessary, provide accruals for probable and reasonably estimable liabilities on the eventual disposition of these matters. The Registrants do not expect the disposition of these matters to have a material adverse effect on the Registrants’ financial condition, results of operations or cash flows.

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Indexed Debt Securities (ZENS) and Securities Related to ZENS (CenterPoint Energy)

12 Months Ended

Dec. 31, 2019

Indexed Debt Securities [Abstract]

Indexed Debt Securities (ZENS) and Securities Related to ZENS (CenterPoint Energy) [Text Block]

Indexed Debt Securities (ZENS) and Securities Related to ZENS (CenterPoint Energy)

(a) Investment in Securities Related to ZENS

A subsidiary of CenterPoint Energy holds shares of certain securities detailed in the table below, which are classified as trading securities and are expected to be held to facilitate CenterPoint Energy’s ability to meet its obligation under the ZENS. Unrealized gains and losses resulting from changes in the market value of the ZENS-Related Securities are recorded in CenterPoint Energy’s Statements of Consolidated Income.

	Shares Held at December 31,
	2019	2018
AT&T Common	10,212,945	10,212,945
Charter Common	872,503	872,912

(b) ZENS

In September 1999, CenterPoint Energy issued ZENS having an original principal amount of $1.0 billion of which $828 million remained outstanding as of December 31, 2019. Each ZENS is exchangeable at the holder’s option at any time for an amount of cash equal to 95% of the market value of the reference shares attributable to such note. The number and identity of the reference shares attributable to each ZENS are adjusted for certain corporate events.

CenterPoint Energy’s reference shares for each ZENS consisted of the following:

	December 31,
	2019	2018
	(in shares)
AT&T Common	0.7185	0.7185
Charter Common	0.061382	0.061382

CenterPoint Energy pays interest on the ZENS at an annual rate of 2% plus the amount of any quarterly cash dividends paid in respect of the reference shares attributable to the ZENS. The principal amount of the ZENS is subject to increases or decreases to the extent that the annual yield from interest and cash dividends on the reference shares is less than or more than 2.309%. The adjusted principal amount is defined in the ZENS instrument as “contingent principal.” As of December 31, 2019, the ZENS, having an original principal amount of $828 million and a contingent principal amount of $75 million, were outstanding and were exchangeable, at the option of the holders, for cash equal to 95% of the market value of the reference shares attributable to the ZENS. As of December 31, 2019, the market value of such shares was approximately $822 million, which would provide an exchange amount of $944 for each $1,000 original principal amount of ZENS. At maturity of the ZENS in 2029, CenterPoint Energy will be obligated to pay in cash the higher of the contingent principal amount of the ZENS or an amount based on the then-current market value of the reference shares, which will include any additional publicly-traded securities distributed with respect to the current reference shares prior to maturity.

The ZENS obligation is bifurcated into a debt component and a derivative component (the holder’s option to receive the appreciated value of the reference shares at maturity). The bifurcated debt component accretes through interest charges annually up to the contingent principal amount of the ZENS in 2029. Such accretion will be reduced by annual cash interest payments, as described above. The derivative component is recorded at fair value and changes in the fair value of the derivative component are recorded in CenterPoint Energy’s Statements of Consolidated Income. Changes in the fair value of the ZENS-Related Securities held by CenterPoint Energy are expected to substantially offset changes in the fair value of the derivative component of the ZENS.

The following table sets forth summarized financial information regarding CenterPoint Energy’s investment in ZENS-Related Securities and each component of CenterPoint Energy’s ZENS obligation. 

	ZENS-Related Securities			Debt Component of ZENS			Derivative Component of ZENS
	(in millions)
Balance as of December 31, 2016	$	953		$	114		$	717
Accretion of debt component of ZENS	—			27			—
2% interest paid	—			(17		)	—
Distribution to ZENS holders	—			(2		)	—
Gain on indexed debt securities	—			—			(49		)
Gain on ZENS-Related Securities	7			—			—
Balance as of December 31, 2017	960			122			668
Accretion of debt component of ZENS	—			21			—
2% interest paid	—			(17		)	—
Sale of ZENS-Related Securities	(398		)	—			—
Distribution to ZENS holders	—			(102		)	(46		)
Gain on indexed debt securities	—			—			(21		)
Loss on ZENS-Related Securities	(22		)	—			—
Balance as of December 31, 2018	540			24			601
Accretion of debt component of ZENS	—			17			—
2% interest paid	—			(17		)	—
Distribution to ZENS holders	—			(5		)	—
Loss on indexed debt securities	—			—			292
Gain on ZENS-Related Securities	282			—			—
Balance as of December 31, 2019	$	822		$	19		$	893

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Mergers and Acquisitions

12 Months Ended

Dec. 31, 2019

Business Combinations [Abstract]

Mergers and Acquisitions [Text Block]

Mergers and Acquisitions (CenterPoint Energy)

Merger with Vectren. On the Merger Date, pursuant to the Merger Agreement, CenterPoint Energy consummated the previously announced Merger and acquired Vectren for approximately $6 billion in cash. Each share of Vectren common stock issued and outstanding immediately prior to the closing was canceled and converted into the right to receive $72.00 in cash per share, without interest. At the closing, each stock unit payable in Vectren common stock or whose value is determined with reference to the value of Vectren common stock, whether vested or unvested, was canceled with cash consideration paid in accordance with the terms of the Merger Agreement. These amounts did not include a stub period cash dividend of $0.41145 per share, which was declared, with CenterPoint Energy’s consent, by Vectren’s board of directors on January 16, 2019, and paid to Vectren stockholders as of the record date of February 1, 2019.

Pursuant to the Merger Agreement and immediately subsequent to the close of the Merger, CenterPoint Energy cash settled $78 million in outstanding share-based awards issued prior to the Merger Date by Vectren to its employees. As a result of the Merger, CenterPoint Energy assumed a liability for these share-based awards of $41 million and recorded an incremental cost of $37 million in Operation and maintenance expenses on its Statements of Consolidated Income during the year ended December 31, 2019 for the accelerated vesting of the awards in accordance with the Merger Agreement.

Subsequent to the close of the Merger, CenterPoint Energy recognized severance totaling $61 million to employees terminated immediately subsequent to the Merger close, inclusive of change of control severance payments to executives of Vectren under existing agreements, and which is included in Operation and maintenance expenses on its Statements of Consolidated Income during the year ended December 31, 2019. Total severance cost for the year ended December 31, 2019 was $102 million.

In connection with the Merger, VUHI and VCC made offers to prepay certain outstanding guaranteed senior notes as required pursuant to certain note purchase agreements previously entered into by VUHI and VCC. See Note 14 for further details.

Following the closing, shares of Vectren common stock, which previously traded under the ticker symbol “VVC” on the NYSE, ceased trading on and were delisted from the NYSE.

The Merger is being accounted for in accordance with ASC 805, Business Combinations, with CenterPoint Energy as the accounting acquirer of Vectren. Identifiable assets acquired and liabilities assumed have been recorded at their estimated fair values on the Merger Date.

Vectren’s regulated operations, comprised of electric generation and electric and natural gas energy delivery services, are subject to the rate-setting authority of the FERC, the IURC and the PUCO, and are accounted for pursuant to U.S. generally accepted accounting principles for regulated operations. The rate-setting and cost-recovery provisions currently in place for Vectren’s regulated operations provide revenues derived from costs including a return on investment of assets and liabilities included in rate base. Thus, the fair value of Vectren’s tangible and intangible assets and liabilities subject to these rate-setting

provisions approximate their carrying values on the Merger Date.  The fair value of regulatory assets not earning a return have been determined using the income approach and are considered Level 3 fair value measurements due to the use of significant judgmental and unobservable inputs.

The fair value of Vectren’s assets acquired and liabilities assumed that are not subject to the rate-setting provisions, including identifiable intangibles, have been determined using the income approach and the market approach. The valuation of Vectren’s long-term debt is primarily considered a Level 2 fair value measurement. All other valuations are considered Level 3 fair value measurements due to the use of significant judgmental and unobservable inputs, including projected timing and amount of future cash flows and discount rates reflecting risk inherent in the future market prices.

The following table presents the purchase price allocation as of December 31, 2019 (in millions):

Cash and cash equivalents	$	16
Other current assets	577
Property, plant and equipment, net	5,147
Identifiable intangibles	297
Regulatory assets	338
Other assets	141
Total assets acquired	6,516
Current liabilities	648
Regulatory liabilities	938
Other liabilities	886
Long-term debt	2,401
Total liabilities assumed	4,873
Net assets acquired	1,643
Goodwill	4,339
Total purchase price consideration	$	5,982

CenterPoint Energy completed a final valuation analysis necessary to determine the fair market values of all of Vectren’s assets and liabilities and the allocation of its purchase price. Changes from the preliminary purchase price allocation originally reported in the first quarter of 2019 primarily included additional information obtained related to intangible assets and the allocation of the fair value between reporting units.

The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed is recognized as goodwill, which is primarily attributable to significant potential strategic benefits to CenterPoint Energy, including growth opportunities for more rate-regulated investment, more customers for existing products and services and additional products and services for existing customers. Additionally, CenterPoint Energy believes the Merger will increase geographic and business diversity as well as scale in attractive jurisdictions and economies. The value assigned to goodwill will not be deductible for tax purposes.

The fair value of the identifiable intangible assets and related useful lives as included in the purchase price allocation as of December 31, 2019 include:

	Weighted Average Useful Lives	Estimated Fair Value
	(in years)	(in millions)
Operation and maintenance agreements	24	$	12
Customer relationships	18	200
Construction backlog	1	27
Trade names	10	58
Total		$	297

Amortization expense related to the operation and maintenance agreements and construction backlog was $24 million in 2019, and is included in Non-utility cost of revenues, including natural gas on CenterPoint Energy’s Statements of Consolidated Income.

Amortization expense related to customer relationships and trade names was $16 million in 2019 and is included in Depreciation and amortization expense on CenterPoint Energy’s Statements of Consolidated Income.

The results of operations for Vectren included in CenterPoint Energy’s Consolidated Financial Statements from the Merger Date for the year ended December 31, 2019 are as follows:

	(in millions)
Operating revenues	$	2,729
Net income	190

The following unaudited pro forma financial information reflects the consolidated results of operations of CenterPoint Energy, assuming the Merger had taken place on January 1, 2018. The unaudited pro forma financial information has been presented for illustrative purposes only and is not necessarily indicative of the consolidated results of operations that would have been achieved had the Merger taken place on the dates indicated or of the future consolidated results of operations of the combined company.

	Year Ended December 31,
	2019			2018
	(in millions)
Operating revenues	$	12,547		$	13,282
Net income	812		(1)	458		(2)

(1) Pro forma net income was adjusted to exclude $37 million of Vectren Merger-related transaction costs incurred in 2019.

(2) Pro forma net income was adjusted to include $37 million of Vectren Merger-related transaction costs incurred in 2019.

CenterPoint Energy incurred integration costs in connection with the Merger of $83 million for the year ended December 31, 2019, which were included in Operation and maintenance expenses in CenterPoint Energy’s Statements of Consolidated Income.

Acquisition of Utility Pipeline Construction Company. An acquisition was made during the year ended December 31, 2019 by CenterPoint Energy’s Infrastructure Services reportable segment, resulting in goodwill and intangible assets of approximately $6 million and $8 million, respectively. The intangible assets primarily relate to backlog and customer relationships. The allocation of the $25 million purchase price has been finalized. The results of operations for the acquired company have been included in CenterPoint Energy’s consolidated financial statements from the date of acquisition and are not significant to the consolidated financial results of CenterPoint Energy. Pro forma results of operations have not been presented for the acquisition because the effects of the acquisition were not significant to CenterPoint Energy’s consolidated financial results for all periods presented.

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STATEMENTS OF CONSOLIDATED SHAREHOLDERS' EQUITY (Parenthetical) - $ / shares						12 Months Ended
	Oct. 17, 2019	Jul. 31, 2019	Apr. 25, 2019	Dec. 12, 2018	Oct. 23, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Aug. 22, 2018
Cumulative preferred stock par value (in dollars per share)						$ 0.01	$ 0.01	$ 0.01
Cumulative preferred stock shares authorized (in shares)						20,000,000	20,000,000	20,000,000
Common stock shares par value (in dollars per share)						$ 0.01	$ 0.01	$ 0.01
Common stock shares authorized (in shares)						1,000,000,000	1,000,000,000	1,000,000,000
Common stock dividends declared per share						$ 0.86	$ 1.1200	$ 1.35
Series A Preferred Stock [Member]
Cumulative preferred stock par value (in dollars per share)						0.01	0.01		$ 1,000
Preferred stock dividends declared per share		$ 30.6250		$ 32.1563		30.6250	32.1563	0.0000
Series B Preferred Stock [Member]
Cumulative preferred stock par value (in dollars per share)						0.01	0.01
Preferred stock dividends declared per share	$ 17.5000	$ 17.5000	$ 17.5000	$ 17.5000	$ 11.6667	$ 52.5000	$ 29.1667	$ 0.0000

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Stock-Based Incentive Compensation Plans and Employee Benefit Plans

12 Months Ended

Dec. 31, 2019

Disclosure of Stock-Based Incentive Compensation Plans and Employee Benefit Plans [Abstract]

Stock-Based Incentive Compensation Plans and Employee Benefit Plans [Text Block]

Stock-Based Incentive Compensation Plans and Employee Benefit Plans

(a) Stock-Based Incentive Compensation Plans (CenterPoint Energy)

CenterPoint Energy has LTIPs that provide for the issuance of stock-based incentives, including stock options, performance awards, restricted stock unit awards and restricted and unrestricted stock awards to officers, employees and non-employee directors.  Approximately 14 million shares of Common Stock are authorized under these plans for awards. CenterPoint Energy issues new shares of its Common Stock to satisfy stock-based payments related to LTIPs. Equity awards are granted to employees without cost to the participants.

Compensation costs for the performance and stock unit awards granted under LTIPs are measured using fair value and expected achievement levels on the grant date. For performance awards with operational goals, the achievement levels are revised as goals are evaluated. The fair value of awards granted to employees is based on the closing stock price of CenterPoint Energy’s Common Stock on the grant date. The compensation expense is recorded on a straight-line basis over the vesting period.  Forfeitures are estimated on the date of grant based on historical averages and estimates are updated periodically throughout the vesting period. 

The performance awards granted in 2019, 2018 and 2017 are distributed based upon the achievement of certain objectives over a three-year performance cycle. The stock unit awards granted in 2019, 2018 and 2017 are service based. The stock unit awards generally vest at the end of a three-year period, provided, however, that stock unit awards granted to non-employee directors vested at the end of a one-year period (for awards granted in 2017) or vested immediately upon grant (for awards granted in 2019 and 2018). Upon vesting, both the performance and stock unit awards are issued to the participants along with the value of dividend equivalents earned over the performance cycle or vesting period.

The following table summarizes CenterPoint Energy’s expenses related to LTIPs for 2019, 2018 and 2017:

	Year Ended December 31,
	2019		2018		2017
	(in millions)
LTIP Compensation expense (1)	$	28	$	26	$	21
Income tax benefit recognized	7		6		8
Actual tax benefit realized for tax deductions	12		5		6

(1) Amounts presented in the table above are included in Operation and maintenance expense in CenterPoint Energy’s Statements of Consolidated Income and shown prior to any amounts capitalized.

The following tables summarize CenterPoint Energy’s LTIP activity for 2019:

	Year Ended December 31, 2019
	Shares (Thousands)		Weighted-Average Grant Date Fair Value		Remaining Average Contractual Life (Years)	Aggregate Intrinsic Value (2) (Millions)
Performance Awards (1)
Outstanding and non-vested as of December 31, 2018	3,818		$	23.91
Granted	1,413		31.16
Forfeited or canceled	(825	)	24.78
Vested and released to participants	(1,074	)	18.97
Outstanding and non-vested as of December 31, 2019	3,332		$	28.36	1.1	$	53
Stock Unit Awards
Outstanding and non-vested as of December 31, 2018	1,060		$	24.08
Granted	470		31.07
Forfeited or canceled	(131	)	27.95
Vested and released to participants	(433	)	20.72
Outstanding and non-vested as of December 31, 2019	966		$	28.46	1.2	$	26

 

(1) Reflects maximum performance achievement.

(2) Reflects the impact of current expectations of achievement and stock price.

The weighted average grant date fair values per unit of awards granted were as follows for 2019, 2018 and 2017:

	Year Ended December 31,
	2019		2018		2017
	(In millions, except for per unit amounts)
Performance Awards
Weighted-average grant date fair value per unit of awards granted	$	31.16	$	26.74	$	26.64
Total intrinsic value of awards received by participants	36		12		7
Vested grant date fair value	20		9		5
Stock Unit Awards
Weighted-average grant date fair value per unit of awards granted	$	31.07	$	26.62	$	26.77
Total intrinsic value of awards received by participants	15		9		9
Vested grant date fair value	9		7		7

As of December 31, 2019, there was $34 million of total unrecognized compensation cost related to non-vested performance and stock awards which is expected to be recognized over a weighted-average period of 1.7 years.

(b) Pension Benefits (CenterPoint Energy)

CenterPoint Energy maintains a non-contributory qualified defined benefit pension plan covering eligible employees, with benefits determined using a cash balance formula. In addition to the non-contributory qualified defined benefit pension plan, CenterPoint Energy maintains unfunded non-qualified benefit restoration plans which allow participants to receive the benefits to which they would have been entitled under CenterPoint Energy’s non-contributory qualified pension plan except for federally mandated limits on qualified plan benefits or on the level of compensation on which qualified plan benefits may be calculated.

As a result of the Merger, CenterPoint Energy now also maintains three additional qualified defined benefit pension plans which are closed to new participants and a non-qualified supplemental retirement plan. The defined benefit pension plans cover eligible full-time regular employees and retirees of Vectren and are primarily non-contributory.

CenterPoint Energy’s net periodic cost includes the following components relating to pension, including the non-qualified benefit plans:

	Year Ended December 31,
	2019			2018			2017
	(in millions)
Service cost (1)	$	40		$	37		$	36
Interest cost (2)	96			79			89
Expected return on plan assets (2)	(105		)	(107		)	(97		)
Amortization of prior service cost (2)	9			9			9
Amortization of net loss (2)	52			43			58
Settlement cost (2) (3)	2			—			—
Curtailment gain (2) (4)	(1		)	—			—
Net periodic cost	$	93		$	61		$	95

 

(1) Amounts presented in the table above are included in Operation and maintenance expense in CenterPoint Energy’s Statements of Consolidated Income, net of regulatory deferrals and amounts capitalized.

(2) Amounts presented in the table above are included in Other, net in CenterPoint Energy’s Statements of Consolidated Income, net of regulatory deferrals.

(3) A one-time, non-cash settlement cost is required when the total lump sum distributions or other settlements of plan benefit obligations during a plan year exceed the service cost and interest cost components of the net periodic cost for that year. In 2019, CenterPoint Energy recognized a non-cash settlement cost due to lump sum settlement payments.

(4) A curtailment gain or loss is required when the expected future services of a significant number of employees are reduced or eliminated for the accrual of benefits. In 2019, CenterPoint Energy recognized a pension curtailment gain related to employees who were terminated after the Merger closed.

CenterPoint Energy used the following assumptions to determine net periodic cost relating to pension benefits:

	Year Ended December 31,
	2019		2018		2017
Discount rate	4.35	%	3.65	%	4.15	%
Expected return on plan assets	6.00		6.00		6.00
Rate of increase in compensation levels	4.60		4.45		4.50

In determining net periodic benefit cost, CenterPoint Energy uses fair value, as of the beginning of the year, as its basis for determining expected return on plan assets.

The following table summarizes changes in the benefit obligation, plan assets, the amounts recognized in the Consolidated Balance Sheets as well as the key assumptions of CenterPoint Energy’s pension plans. The measurement dates for plan assets and obligations were December 31, 2019 and 2018.

	December 31,
	2019			2018
	(in millions, except for actuarial assumptions)
Change in Benefit Obligation
Benefit obligation, beginning of year	$	2,013		$	2,225
Plan obligations assumed in Merger	332			—
Service cost	40			37
Interest cost	96			79
Benefits paid	(244		)	(201		)
Actuarial (gain) loss (1)	216			(127		)
Plan amendment	1			—
Curtailment	(1		)	—
Benefit obligation, end of year	2,453			2,013
Change in Plan Assets
Fair value of plan assets, beginning of year	1,516			1,801
Plan assets assumed in Merger	286			—
Employer contributions	109			69
Benefits paid	(244		)	(201		)
Actual investment return	338			(153		)
Fair value of plan assets, end of year	2,005			1,516
Funded status, end of year	$	(448	)	$	(497	)
Amounts Recognized in Balance Sheets
Current liabilities-other	$	(8	)	$	(7	)
Other liabilities-benefit obligations	(440		)	(490		)
Net liability, end of year	$	(448	)	$	(497	)
Actuarial Assumptions
Discount rate (2)	3.20		%	4.35		%
Expected return on plan assets (3)	5.75			6.00
Rate of increase in compensation levels	4.95			4.60
Interest crediting rate	3.25			3.75

(1) Significant sources of loss for 2019 include the decrease in discount rate from 4.35% to 3.20%. Significant sources of gain for 2018 include the increase in discount rate from 3.65% to 4.35% and the mortality projection scale change from MP2017 to MP2018.

(2) The discount rate assumption was determined by matching the projected cash flows of CenterPoint Energy’s plans against a hypothetical yield curve of high-quality corporate bonds represented by a series of annualized individual discount rates from one-half to 99 years.

(3) The expected rate of return assumption was developed using the targeted asset allocation of CenterPoint Energy’s plans and the expected return for each asset class.

The following table displays pension benefits related to CenterPoint Energy’s pension plans that have accumulated benefit obligations in excess of plan assets:

	December 31,
	2019				2018
	Pension (Qualified)		Pension (Non-qualified)		Pension (Qualified)		Pension (Non-qualified)
	(in millions)
Accumulated benefit obligation	$	2,352	$	68	$	1,930	$	61
Projected benefit obligation	2,385		68		1,952		61
Fair value of plan assets	2,005		—		1,516		—

The accumulated benefit obligation for all defined benefit pension plans on CenterPoint Energy’s Consolidated Balance Sheets was $2,420 million and $1,991 million as of December 31, 2019 and 2018, respectively.

Multi-employer Pension Plan

CenterPoint Energy, through its Infrastructure Services reportable segment, participates in several industry wide multi-employer pension plans for its collective bargaining employees which provide for monthly benefits based on length of service. The risks of participating in multi-employer pension plans are different from the risks of participating in single-employer pension plans in the following respects: (1) assets contributed to the multi-employer plan by one employer may be used to provide benefits to employees of other participating employers, (2) if a participating employer stops contributing to the plan, the unfunded obligations of the plan allocable to such withdrawing employer may be borne by the remaining participating employers and (3) if CenterPoint Energy stops participation in some of its multi-employer pension plans, CenterPoint Energy may be required to pay those plans an amount based on its allocable share of the underfunded status of the plan, referred to as a withdrawal liability.

Expense is recognized as payments are accrued for work performed or when withdrawal liabilities are probable and estimable. Expense associated with multi-employer plans of $52 million during the year ended December 31, 2019. During 2019, CenterPoint Energy made contributions to these multi-employer plans on behalf of employees that participate in approximately 215 local unions. Contracts with these unions are negotiated with trade agreements through two primary contractor associations. These trade agreements have varying expiration dates ranging from 2020 through 2022. The average contribution related to these local unions was less than $1 million, and the largest contribution was approximately $5 million. Multiple unions can contribute to a single multi-employer plan. CenterPoint Energy made contributions to at least 72 plans in 2019, eight of which are considered significant plans based on, among other things, the amount of the contributions, the number of employees participating in the plan, and the funded status of the plan.

CenterPoint Energy’s participation in the significant plans is outlined in the following table. The EIN / Pension Plan Number column provides the EIN and three-digit pension plan numbers. The most recent Pension Protection Act Zone Status available in 2019 is for the plan year end at January 31, 2019 for the Central Pension Fund, May 31, 2019 for the Indiana Pension Laborers Fund, December 31, 2018 for the Pipeline Industry Benefit Fund, December 31, 2018 for the Laborers District Council & Contractors’ Pension Fund of Ohio, April 30, 2019 for the Ohio Operating Engineers Pension Fund, April 30, 2019 for the Operating Engineers Local 324 Fringe Benefit Fund, December 31, 2018 for the Minnesota Laborers Pension Fund, and December 31, 2018 for the Laborers’ Combined Fund of Western Pennsylvania. Generally, plans in the red zone are less than 65% funded, plans in the yellow zone are less than 80% funded and plans in the green zone are at least 80% funded. The FIP/RP Status Pending / Implemented column indicates plans for which a FIP or RP is either pending or has been implemented. The multi-employer contributions listed in the table below are CenterPoint Energy’s multi-employer contributions made in 2019.

Federal law requires pension plans in endangered status to adopt a FIP and plans in critical status to adopt a RP aimed at

restoring the financial health of the plan. In December 2014, the Multi-employer Pension Reform Act of 2014 was passed and permanently extended the Pension Protection Act of 2006 multi-employer plan critical and endangered status funding rules, among other things, including providing a provision for a plan sponsor to suspend or reduce benefit payments to preserve plans in critical and declining status.

		Pension Protection Act Zone Status		Multi-employer Contributions
Pension Fund	EIN/Pension Plan Number	2019	FIP/RP Status Pending/Implemented	2019		Surcharge Imposed
				(in millions)
Central Pension Fund	36-6052390-001	Green	No	$	12	No
Indiana Laborers Pension Fund	35-6027150-001	Green	No	5		No
Pipeline Industry Benefit Fund	73-0742835-001	Green	No	5		No
Laborers District Fund of Ohio	31-6129964-001	Green	No	4		No
Ohio Operating Engineers Pension Fund	31-6129968-001	Green	No	3		No
Operating Engineers Local #324 Fund (1)	38-1900637-001	Red	Implemented	3		No
Minnesota Laborers Pension Fund	41-6159599-001	Green	No	3		No
Laborers’ Combined Fund of Western PA (2)	25-6135576-001	Red	Implemented	2		No
Other				15
Total Contributions				$	52

(1) The Operating Engineers Local #324 Fringe Benefits Fund was certified to be in “critical” status for the plan year ending April 30, 2019. In an effort to improve the plan’s funding situation, on March 17, 2011, the trustees adopted a plan amendment, which reduced benefit accruals and eliminated some ancillary benefits, and adopted an RP that will be effective from May 1, 2013 through April 30, 2023 or until the plan is no longer in critical status. On April 27, 2015, the trustees updated the RP to change the annual standard for meeting the requirements of the RP. The trustees further updated the RP on January 29, 2019. The annual standard is that actuarial projections updated for each year show the fund is expected to remain solvent for a 20-year projection period.

(2) The Laborers’ Combined Fund of Western Pennsylvania was previously deemed in critical status. The trustees adopted a FIP that is scheduled to run through December 31, 2020 and provided for changes in adjustable benefits and increases in the employer contribution rate.

While not considered significant to CenterPoint Energy, there are four plans in red zone status receiving CenterPoint Energy contributions. There are also five other plans where CenterPoint Energy contributions exceed 5% of each plan’s total contributions; however, none of these plans are considered significant to CenterPoint Energy.

On February 3, 2020, CenterPoint Energy, through its subsidiary VUSI, entered into the Purchase Agreement to sell the businesses within its Infrastructure Services reportable segment. The transaction is expected to close in the second quarter of 2020. For further information, see Notes 6 and 23. As a result, CenterPoint Energy will no longer participate in the multi-employer pension plans discussed above.

(c) Postretirement Benefits

CenterPoint Energy provides certain healthcare and life insurance benefits for eligible retired employees on both a contributory and non-contributory basis. The Registrants’ employees (other than employees of Vectren and its subsidiaries) who were hired before January 1, 2018 and who have met certain age and service requirements at retirement, as defined in the plans, are eligible to participate in these benefit plans. Employees hired on or after January 1, 2018 are not eligible for these benefits, except that such employees represented by IBEW Local Union 66 are eligible to participate in certain of the benefits, subject to the applicable age and service requirements. With respect to retiree medical and prescription drug benefits, employees represented by the IBEW Local Union 66 who retire on or after January 1, 2017, and their dependents, receive any such benefits exclusively through the NECA/IBEW Family Medical Care Plan pursuant to the terms of the renegotiated collective bargaining agreement entered into in May 2016. Houston Electric and CERC are required to fund a portion of their obligations in accordance with rate orders. All other obligations are funded on a pay-as-you-go basis.

As a result of the Merger, CenterPoint Energy now maintains an additional postretirement benefit plan. The postretirement benefit plan provides health care and life insurance benefits, which are a combination of self-insured and fully insured programs, to eligible Vectren retirees on both a contributory and non-contributory basis.

Postretirement benefits are accrued over the active service period of employees. The net postretirement benefit cost includes the following components:

	Year Ended December 31,
	2019									2018									2017
	CenterPoint Energy			Houston Electric			CERC			CenterPoint Energy			Houston Electric			CERC			CenterPoint Energy			Houston Electric			CERC
	(in millions)
Service cost (1)	$	3		$	1		$	1		$	2		$	—		$	1		$	2		$	1		$	1
Interest cost (2)	15			7			5			13			8			4			16			9			5
Expected return on plan assets (2)	(5		)	(4		)	(1		)	(5		)	(4		)	(1		)	(5		)	(4		)	(1		)
Amortization of prior service cost (credit) (2)	(5		)	(6		)	1			(5		)	(5		)	1			(5		)	(6		)	1
Net postretirement benefit cost (credit)	$	8		$	(2	)	$	6		$	5		$	(1	)	$	5		$	8		$	—		$	6

(1) Amounts presented in the table above are included in Operation and maintenance expense in each of the Registrants’ respective Statements of Consolidated Income, net of regulatory deferrals and amounts capitalized.

(2) Amounts presented in the table above are included in Other, net in each of the Registrants’ respective Statements of Consolidated Income, net of regulatory deferrals.

The following assumptions were used to determine net periodic cost relating to postretirement benefits:

	Year Ended December 31,
	2019						2018						2017
	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC
Discount rate	3.20	%	3.20	%	3.20	%	3.60	%	3.60	%	3.60	%	4.15	%	4.15	%	4.15	%
Expected return on plan assets	4.60		4.70		4.15		4.55		4.75		3.85		4.50		4.75		3.60

The following table summarizes changes in the benefit obligation, plan assets, the amounts recognized in consolidated balance sheets and the key assumptions of the postretirement plans. The measurement dates for plan assets and benefit obligations were December 31, 2019 and 2018.

	December 31,
	2019									2018
	CenterPoint Energy			Houston Electric			CERC			CenterPoint Energy			Houston Electric			CERC
	(in millions)
Change in Benefit Obligation
Benefit obligation, beginning of year	$	331		$	166		$	110		$	386		$	225		$	109
Plan obligations assumed in Merger	37			—			—			—			—			—
Service cost	3			1			1			2			—			1
Interest cost	15			7			5			13			8			4
Participant contributions	8			2			4			7			2			4
Benefits paid	(26		)	(13		)	(8		)	(25		)	(13		)	(9		)
Plan amendment	9			3			5			—			—			—
Actuarial (gain) loss (1)	(21		)	(4		)	(15		)	(52		)	(56		)	1
Benefit obligation, end of year	356			162			102			331			166			110
Change in Plan Assets
Fair value of plan assets, beginning of year	114			89			25			120			93			26
Employer contributions	17			10			3			14			9			4
Participant contributions	8			2			4			7			2			4
Benefits paid	(26		)	(13		)	(8		)	(25		)	(13		)	(9		)
Actual investment return	15			13			3			(2		)	(2		)	—
Fair value of plan assets, end of year	128			101			27			114			89			25
Funded status, end of year	$	(228	)	$	(61	)	$	(75	)	$	(217	)	$	(77	)	$	(85	)
Amounts Recognized in Balance Sheets
Current liabilities-other	$	(8	)	$	—		$	(3	)	$	(6	)	$	—		$	(3	)
Other liabilities-benefit obligations	(220		)	(61		)	(72		)	(211		)	(77		)	(82		)
Net liability, end of year	$	(228	)	$	(61	)	$	(75	)	$	(217	)	$	(77	)	$	(85	)
Actuarial Assumptions
Discount rate (2)	3.25		%	3.25		%	3.25		%	4.35		%	4.35		%	4.35		%
Expected return on plan assets (3)	3.95			4.05			3.35			4.60			4.70			4.15
Medical cost trend rate assumed for the next year - Pre-65	5.50			5.50			5.50			5.95			5.95			5.95
Medical/prescription drug cost trend rate assumed for the next year - Post-65	5.75			5.75			5.75			28.60			28.60			28.60
Prescription drug cost trend rate assumed for the next year - Pre-65	8.00			8.00			8.00			9.20			9.20			9.20
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)	4.50			4.50			4.50			4.50			4.50			4.50
Year that the cost trend rates reach the ultimate trend rate - Pre-65	2028			2028			2028			2026			2026			2026
Year that the cost trend rates reach the ultimate trend rate - Post-65	2029			2029			2029			2027			2027			2027

(1) Significant sources of gain for 2019 include favorable cost trend rates and benefit claims experience in addition to the change in mortality projection scale from MP2018 to MP2019. Significant sources of gain for 2018 include the increase in the discount rate from 3.60% to 4.35%, favorable benefit claims experience and cost trend rates in addition to the change in mortality projection scale from MP2017 to MP2018.

(2) The discount rate assumption was determined by matching the projected cash flows of the plans against a hypothetical yield curve of high-quality corporate bonds represented by a series of annualized individual discount rates from one-half to 99 years.

(3) The expected rate of return assumption was developed using the targeted asset allocation of the plans and the expected return for each asset class.

(d) Accumulated Other Comprehensive Income (Loss) (CenterPoint Energy and CERC)

CenterPoint Energy recognizes the funded status of its pension and other postretirement plans on its Consolidated Balance Sheets. To the extent this obligation exceeds amounts previously recognized in the Statements of Consolidated Income, CenterPoint Energy records a regulatory asset for that portion related to its rate regulated utilities. To the extent that excess liability does not relate to a rate regulated utility, the offset is recorded as a reduction to equity in accumulated other comprehensive income.

Amounts recognized in accumulated other comprehensive loss (gain) consist of the following:

	December 31,
	2019								2018
	Pension Benefits		Postretirement Benefits						Pension Benefits		Postretirement Benefits
	CenterPoint Energy		CenterPoint Energy			CERC			CenterPoint Energy		CenterPoint Energy			CERC
	(in millions)
Unrecognized actuarial loss (gain)	$	105	$	(16	)	$	(12	)	$	109	$	(7	)	$	(3	)
Unrecognized prior service cost	—		7			7			1		5			5
Deferred tax benefit	—		—			—			—		—			(9		)
Net amount recognized in accumulated other comprehensive loss (gain)	$	105	$	(9	)	$	(5	)	$	110	$	(2	)	$	(7	)

The changes in plan assets and benefit obligations recognized in other comprehensive income during 2019 are as follows:

	Pension Benefits			Postretirement Benefits
	CenterPoint Energy			CenterPoint Energy			CERC
	(in millions)
Net loss (gain)	$	4		$	(8	)	$	(6	)
Amortization of net loss	(8		)	—			—
Amortization of prior service cost	(1		)	1			(1		)
Total recognized in comprehensive income	$	(5	)	$	(7	)	$	(7	)
Total expense recognized in net periodic costs and Other comprehensive income	$	87		$	1		$	(1	)

(e) Pension Plan Assets (CenterPoint Energy)

In managing the investments associated with the benefit plans, CenterPoint Energy’s objective is to achieve and maintain a fully funded plan. This objective is expected to be achieved through an investment strategy that manages liquidity requirements while maintaining a long-term horizon in making investment decisions and efficient and effective management of plan assets.

As part of the investment strategy discussed above, CenterPoint Energy maintained the following weighted average allocation targets for its pension plans as of December 31, 2019:

	Minimum		Maximum
U.S. equity	19	%	29	%
International equity	8	%	18	%
Real estate	3	%	9	%
Fixed income	52	%	62	%
Cash	0	%	2	%

The following tables set forth by level, within the fair value hierarchy (see Note 10), CenterPoint Energy’s pension plan assets at fair value as of December 31, 2019 and 2018:

	Fair Value Measurements as of December 31,
	2019										2018
	(Level 1)			(Level 2)		(Level 3)		Total			(Level 1)			(Level 2)		(Level 3)		Total
	(in millions)
Cash	$	(7	)	$	—	$	—	$	(7	)	$	19		$	—	$	—	$	19
Corporate bonds:
Investment grade or above	—			699		—		699			—			368		—		368
Equity securities:
U.S. companies	69			—		—		69			60			—		—		60
Cash received as collateral from securities lending	61			—		—		61			77			—		—		77
U.S. treasuries	232			—		—		232			196			—		—		196
Mortgage backed securities	—			8		—		8			—			6		—		6
Asset backed securities	—			3		—		3			—			1		—		1
Municipal bonds	—			44		—		44			—			27		—		27
Mutual funds (2)	270			—		—		270			167			—		—		167
International government bonds	—			21		—		21			—			16		—		16
Obligation to return cash received as collateral from securities lending	(61		)	—		—		(61		)	(77		)	—		—		(77		)
Total investments at fair value	$	564		$	775	$	—	$	1,339		$	442		$	418	$	—	$	860
Investments measured by net asset value per share or its equivalent (1) (2)								666										656
Total Investments								$	2,005									$	1,516

(1) Represents investments in common collective trust funds.

(2) The amounts invested in mutual funds and common collective trust funds were allocated as follows:

	As of December 31,
	2019				2018
	Mutual Funds		Common Collective Trust Funds		Mutual Funds		Common Collective Trust Funds
International equities (1)	31	%	29	%	85	%	41	%
U.S. equities	49	%	51	%	15	%	5	%
Real estate	1	%	6	%	—	%	—	%
Fixed income	19	%	14	%	—	%	54	%

(1) The amounts invested in international equities for 2018 include allocations of 34% in mutual funds and 4% in common collective trust funds,which were previously reported as allocations in emerging market equities.

The pension plans utilized both exchange traded and over-the-counter financial instruments such as futures, interest rate options and swaps that were marked to market daily with the gains/losses settled in the cash accounts. The pension plans did not include any holdings of CenterPoint Energy Common Stock as of December 31, 2019 or 2018.

(f) Postretirement Plan Assets

In managing the investments associated with the postretirement plans, the Registrants’ objective is to achieve and maintain a fully funded plan. This objective is expected to be achieved through an investment strategy that manages liquidity requirements while maintaining a long-term horizon in making investment decisions and efficient and effective management of plan assets.

As part of the investment strategy discussed above, the Registrants maintained the following weighted average allocation targets for the postretirement plans as of December 31, 2019:

	CenterPoint Energy				Houston Electric				CERC
	Minimum		Maximum		Minimum		Maximum		Minimum		Maximum
U.S. equity	13	%	23	%	13	%	23	%	15	%	25	%
International equity	3	%	13	%	3	%	13	%	2	%	12	%
Fixed income	69	%	79	%	69	%	79	%	68	%	78	%
Cash	0	%	2	%	0	%	2	%	0	%	2	%

The following table presents mutual funds by level, within the fair value hierarchy, the Registrants’ postretirement plan assets at fair value as of December 31, 2019 and 2018:

	Fair Value Measurements as of December 31,
	2019								2018
	Mutual Funds
	(Level 1)		(Level 2)		(Level 3)		Total		(Level 1)		(Level 2)		(Level 3)		Total
	(in millions)
CenterPoint Energy	$	128	$	—	$	—	$	128	$	114	$	—	$	—	$	114
Houston Electric	101		—		—		101		89		—		—		89
CERC	27		—		—		27		25		—		—		25

The amounts invested in mutual funds were allocated as follows:

	As of December 31,
	2019						2018
	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC
Fixed income	71	%	71	%	69	%	74	%	74	%	73	%
U.S. equities	21	%	21	%	24	%	19	%	19	%	21	%
International equities	8	%	8	%	7	%	7	%	7	%	6	%

(g) Benefit Plan Contributions

The Registrants made the following contributions in 2019 and expect to make the following minimum contributions in 2020 to the indicated benefit plans below:

	Contributions in 2019						Expected Minimum Contributions in 2020
	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC
	(in millions)
Qualified pension plans	$	86	$	—	$	—	$	76	$	—	$	—
Non-qualified pension plans	23		—		—		7		—		—
Postretirement benefit plans	17		10		3		17		9		3

The following benefit payments are expected to be paid by the pension and postretirement benefit plans:

	Pension Benefits		Postretirement Benefits
	CenterPoint Energy		CenterPoint Energy		Houston Electric		CERC
	(in millions)
2020	$	180	$	18	$	8	$	5
2021	178		18		8		4
2022	180		19		9		5
2023	181		20		10		5
2024	177		21		10		6
2025-2029	824		112		54		30

(h) Savings Plan

CenterPoint Energy maintains the CenterPoint Energy Savings Plan, a tax-qualified employee savings plan that includes a cash or deferred arrangement under Section 401(k) of the Code, and an employee stock ownership plan under Section 4975(e)(7) of the Code. Under the plan, participating employees may make pre-tax or Roth contributions and, if eligible, after-tax contributions up to certain federally mandated limits. Participating Registrants provide matching contributions and, as of January 1, 2020, nonelective contributions, if eligible, up to certain limits. CenterPoint Energy, through the Merger, also acquired additional defined contribution retirement savings plans sponsored by Vectren and its subsidiaries that are qualified under sections 401(a) and 401(k) of the Code, one of which merged into the CenterPoint Energy Savings Plan as of January 1, 2020.

The CenterPoint Energy Savings Plan has significant holdings of Common Stock. As of December 31, 2019, 11,051,800 shares of Common Stock were held by the savings plan, which represented approximately 13% of its investments. Given the concentration of the investments in Common Stock, the savings plan and its participants have market risk related to this investment. The savings plan limits the percentage of future contributions that can be invested in Common Stock to 25% and prohibits transfers of account balances where the transfer would result in more than 25% of a participant’s total account balance invested in Common Stock.

CenterPoint Energy allocates the savings plan benefit expense to Houston Electric and CERC related to their respective employees. The following table summarizes the Registrants’ savings plan benefit expense for 2019, 2018 and 2017:

	Year Ended December 31,
	2019						2018						2017
	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC
	(in millions)
Savings plan benefit  expenses (1)	$	58	$	18	$	18	$	43	$	17	$	18	$	41	$	17	$	17

(1) Amounts presented in the table above are included in Operation and maintenance expense in the Registrants’ respective Statements of Consolidated Income and shown prior to any amounts capitalized.

(i) Other Benefits Plans

The Registrants participate in CenterPoint Energy’s plans that provide postemployment benefits for certain former or inactive employees, their beneficiaries and covered dependents, after employment but before retirement (primarily healthcare and life insurance benefits for participants in the long-term disability plan).

CenterPoint Energy maintains non-qualified deferred compensation plans, including plans acquired in the Merger, that provide benefits payable to eligible directors, officers and select employees or their designated beneficiaries at specified future dates or upon termination, retirement or death. Benefit payments are made from the general assets of the participating Registrants.

Expenses related to other benefit plans were recorded as follows:

	Year Ended December 31,
	2019						2018						2017
	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC
	(in millions)
Postemployment benefits	$	2	$	1	$	1	$	3	$	4	$	1	$	6	$	1	$	4
Deferred compensation plans	4		1		—		3		1		—		3		1		—

Amounts related to other benefit plans were included in Benefit Obligations in the Registrants’ accompanying Consolidated Balance Sheets as follows:

	December 31, 2019						December 31, 2018
	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC
	(in millions)
Postemployment benefits	$	11	$	3	$	7	$	11	$	3	$	7
Deferred compensation plans	41		8		3		42		9		3
Split-dollar life insurance arrangements	32		1		—		36		1		—

(j) Change in Control Agreements and Other Employee Matters

CenterPoint Energy has a change in control plan, which was amended and restated on May 1, 2017. The plan generally provides, to the extent applicable, in the case of a change in control of CenterPoint Energy and covered termination of employment, for severance benefits of up to three times annual base salary plus bonus, and other benefits. Certain CenterPoint Energy officers, including the Executive Chairman, are participants under the plan.

Certain key employees of Vectren and its subsidiaries have change in control agreements or employment agreements that provide payments and other benefits upon a covered termination of employment.

As of December 31, 2019, the Registrants’ employees were covered by collective bargaining agreements as follows:

		Percentage of Employees Covered
	Agreement Expiration	CenterPoint Energy		Houston Electric		CERC
IBEW Local 66	May 2020	10	%	51	%	—
OPEIU Local 12 and Mankato	March and May 2021	2	%	—		3	%
Gas Workers Union Local 340	April 2020	3	%	—		12	%
IBEW Locals 949 & 1393 and USW Locals 12213 & 7441	December 2020	4	%	—		7	%
USW Locals 13-227 & 13-1 and IBEW Local 702	June and July 2022	5	%	—		12	%
Teamsters Local 135	September 2021	—		—		—
UWUA Local 175	October 2021	1	%	—		—
Trade Agreements of Infrastructure Services through the DCA and PLCA (1)	Various expiration dates in 2020–2022	27	%	—		—
Total		52	%	51	%	34	%

(1)

Infrastructure Services negotiates various trade agreements through contractor associations. The two primary associations are the DCA and the PLCA.  These trade agreements are with a variety of construction unions including Laborer’s International Union of North America, International Union of Operating Engineers, United Association of Journeymen and Apprentices of the Plumbing and Pipe Fitting Industry, and Teamsters. The trade agreements have varying expiration dates in 2020, 2021 and 2022. In addition, these subsidiaries have various project agreements and small local agreements.  These agreements expire upon completion of a specific project or on various dates throughout the year.

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Subsequent Events

12 Months Ended

Dec. 31, 2019

Subsequent Events [Abstract]

Subsequent Events [Text Block]

Subsequent Events (CenterPoint Energy)

Proposed Divestiture of Infrastructure Services (CenterPoint Energy)

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 to PowerTeam Services. Subject to the terms and conditions of the Securities Purchase Agreement, PowerTeam Services has agreed to purchase all of the outstanding equity interests of VISCO for approximately $850 million, subject to customary adjustments set forth in the Securities Purchase Agreement, including adjustments based on VISCO’s net working capital at closing, indebtedness, cash and cash equivalents and transaction expenses. Per the Securities Purchase Agreement, VISCO will be converted from a wholly-owned corporation to a limited liability company that is disregarded for federal income tax purposes immediately prior to the closing of the transaction resulting in the sale of membership units at closing.  The sale will be considered an asset sale for tax purposes requiring the net deferred tax liabilities of approximately $123 million as of December 31, 2019 to be recognized; therefore, any deferred tax assets and liabilities within the reporting unit are not included in the carrying amount of the assets and liabilities that will be transferred to PowerTeam Services.

The completion of the sale is subject to customary closing conditions, including, among others (i) the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Act and (ii) customary conditions regarding the accuracy of the representations and warranties and compliance by the parties in all material respects with their respective obligations under the Securities Purchase Agreement. The Securities Purchase Agreement also includes customary termination provisions, including if the closing of the sale has not occurred on or before June 3, 2020. The sale is not subject to a financing condition and is expected to close in the second quarter of 2020, subject to satisfaction of the foregoing conditions, among other things.

On February18, 2020, CenterPoint Energy received notice from the Federal Trade Commission granting early termination of the waiting period under the Hart-Scott-Rodino Act in connection with the proposed sale of Infrastructure Services.

Proposed Divestiture of Energy Services (CenterPoint Energy and CERC)

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, to Athena Energy Services. This transaction does not include CEIP and its assets. Subject to the terms and conditions of the Equity Purchase Agreement, Athena Energy Services has agreed to purchase all of the outstanding equity interests of CES for approximately $400 million, subject to customary adjustments set forth in the Equity Purchase Agreement, including adjustments based on CES’s net working capital at closing, indebtedness and transaction expenses. Per the Equity Purchase Agreement, CES will be converted from a wholly-owned corporation to a limited liability company that is disregarded for federal income tax purposes immediately prior to the closing of the transaction resulting in the sale of membership units at closing. The sale will be considered an asset sale

for tax purposes requiring the net deferred tax liabilities of approximately $25 million as of December 31, 2019 to be recognized; therefore, any deferred tax assets and liabilities within the reporting unit are not included in the carrying amount of the assets and liabilities that will be transferred to the buyer.

The completion of the sale is subject to customary closing conditions, including, among others (i) the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Act and (ii) the conversion of CES to a Delaware limited liability company, (iii) the distribution of the equity interests in CenterPoint Energy Intrastate Pipelines, LLC held by CES to CERC Corp. or its affiliates and (iv) customary conditions regarding the accuracy of the representations and warranties and compliance by the parties in all material respects with their respective obligations under the Equity Purchase Agreement. The Equity Purchase Agreement includes customary termination provisions, including if the closing of the transaction has not occurred on or before June 24, 2020.The sale is not subject to a financing condition and is expected to close in the second quarter of 2020, subject to satisfaction of the foregoing conditions, among other things.

CenterPoint Energy Dividend Declarations (CenterPoint Energy)

Equity Instrument	Declaration Date	Record Date	Payment Date	Per Share
Common Stock	February 3, 2020	February 20, 2020	March 12, 2020	$	0.2900
Series A Preferred Stock	February 3, 2020	February 14, 2020	March 2, 2020	30.6250
Series B Preferred Stock	February 3, 2020	February 14, 2020	March 2, 2020	17.5000

Enable Distributions Declarations (CenterPoint Energy)

Equity Instrument	Declaration Date	Record Date	Payment Date	Per Unit Distribution		Expected Cash Distribution
						(in millions)
Enable common units	February 7, 2020	February 18, 2020	February 25, 2020	$	0.3305	$	77
Enable Series A Preferred Units	February 7, 2020	February 7, 2020	February 14, 2020	0.6250		9

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Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2019

Property, Plant and Equipment [Abstract]

Schedule of Property, Plant and Equipment [Table Text Block]

Property, plant and equipment includes the following:

		December 31, 2019						December 31, 2018
	Weighted Average Useful Lives	Property, Plant and Equipment, Gross		Accumulated Depreciation & Amortization		Property, Plant and Equipment, Net		Property, Plant and Equipment, Gross		Accumulated Depreciation & Amortization		Property, Plant and Equipment, Net
	(in years)	(in millions)
CenterPoint Energy
Electric Transmission & Distribution	37	$	14,360	$	4,634	$	9,726	$	12,148	$	3,746	$	8,402
Electric Generation (1)	27	1,780		698		1,082		—		—		—
Natural Gas Distribution	29	12,695		3,731		8,964		7,257		2,128		5,129
Energy Services (2)	27	136		53		83		121		43		78
Infrastructure Services (3)	10	317		22		295		—		—		—
Other property	19	1,397		602		795		741		306		435
Total		$	30,685	$	9,740	$	20,945	$	20,267	$	6,223	$	14,044
Houston Electric
Electric Transmission	46	$	3,358	$	674	$	2,684	$	3,077	$	650	$	2,427
Electric Distribution	35	7,876		2,586		5,290		7,524		2,553		4,971
Other transmission & distribution property	19	1,595		537		1,058		1,547		543		1,004
Total		$	12,829	$	3,797	$	9,032	$	12,148	$	3,746	$	8,402

		December 31, 2019						December 31, 2018
	Weighted Average Useful Lives	Property, Plant and Equipment, Gross		Accumulated Depreciation & Amortization		Property, Plant and Equipment, Net		Property, Plant and Equipment, Gross		Accumulated Depreciation & Amortization		Property, Plant and Equipment, Net
	(in years)	(in millions)
CERC
Natural Gas Distribution	29	$	7,933	$	2,208	$	5,725	$	7,257	$	2,128	$	5,129
Energy Services (2)	27	136		53		83		121		43		78
Other property	16	55		27		28		53		34		19
Total		$	8,124	$	2,288	$	5,836	$	7,431	$	2,205	$	5,226

(1) SIGECO and AGC own a 300 MW unit at the Warrick Power Plant (Warrick Unit 4) as tenants in common. SIGECO’s share of the cost of this unit as of December 31, 2019, is $194 million with accumulated depreciation totaling $137 million. AGC and SIGECO share equally in the cost of operation and output of the unit. SIGECO’s share of operating costs is included in Operation and maintenance expense in CenterPoint Energy’s Statements of Consolidated Income.

(2) 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. The transaction is expected to close in the second quarter of 2020. For further information, see Notes 6 and 23.

(3) 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 is expected to close in the second quarter of 2020. For further information, see Notes 6 and 23.

Depreciation and Amortization [Table Text Block]

The following table presents depreciation and amortization expense for 2019, 2018 and 2017:

	Year Ended December 31,
	2019						2018						2017
	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC
	(in millions)
Depreciation	$	920	$	339	$	281	$	626	$	342	$	264	$	619	$	354	$	243
Amortization of securitized regulatory assets	271		271		—		531		531		—		329		329		—
Other amortization	96		38		24		86		44		29		88		41		36
Total	$	1,287	$	648	$	305	$	1,243	$	917	$	293	$	1,036	$	724	$	279

Asset Retirement Obligation [Table Text Block]

A reconciliation of the changes in the ARO liability recorded in Other non-current liabilities on each of the Registrants’ respective Consolidated Balance Sheets is as follows:

	December 31, 2019						December 31, 2018
	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy			Houston Electric			CERC
	(in millions)
Beginning balance	$	258	$	34	$	221	$	281		$	35		$	243
Addition from Merger with Vectren	116		—		—		—			—			—
Accretion expense (1)	16		1		10		10			1			9
Revisions in estimates (2)	149		7		94		(33		)	(2		)	(31		)
Ending balance	$	539	$	42	$	325	$	258		$	34		$	221

(1) Reflected in Regulatory assets on each of the Registrants’ respective Consolidated Balance Sheets.

(2)

In 2019, the Registrants reflected an increase in their respective ARO liability, which is primarily attributable to decreases in the long-term interest rates used for discounting in the ARO calculation and increased estimated closure costs for CenterPoint Energy’s electric generation. In 2018, CenterPoint Energy and CERC reflected a decrease in their respective ARO liability, which is primarily attributable to increases in the long-term interest rates used for discounting in the ARO calculation.

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Leases (Tables)

12 Months Ended

Dec. 31, 2019

Leases [Abstract]

Lease, Cost [Table Text Block]

The components of lease cost, included in Operation and maintenance expense on the Registrants’ respective Statements of Consolidated Income, are as follows:

	Year Ended December 31, 2019
	CenterPoint Energy		Houston Electric		CERC
	(in millions)
Operating lease cost	$	25	$	—	$	5
Short-term lease cost	75		23		—
Variable lease cost	1		—		1
Total lease cost	$	101	$	23	$	6

Operating Lease, Lease Income [Table Text Block]

The components of lease income were as follows:

	Year Ended December 31, 2019
	CenterPoint Energy		Houston Electric		CERC
	(in millions)
Operating lease income	$	4	$	2	$	1
Variable lease income	2		—		—
Total lease income	$	6	$	2	$	1

Supplemental Balance Sheet Information Related To Leases [Table Text Block]

Supplemental balance sheet information related to leases was as follows:

	December 31, 2019
	CenterPoint Energy			Houston Electric			CERC
	(in millions, except lease term and discount rate)
Assets:
Operating ROU assets (1)	$	63		$	1		$	24
Total leased assets	$	63		$	1		$	24
Liabilities:
Current operating lease liability (2)	$	21		$	—		$	4
Non-current operating lease liability (3)	42			1			20
Total leased liabilities	$	63		$	1		$	24
Weighted-average remaining lease term (in years) - operating leases	5.1			5.2			7.7
Weighted-average discount rate - operating leases	3.42		%	3.52		%	3.67		%

(1) Reported within Other assets in the Registrants’ respective Consolidated Balance Sheets.

(2) Reported within Current other liabilities in the Registrants’ respective Consolidated Balance Sheets.

(3)

Reported within Other liabilities in the Registrants’ respective Consolidated Balance Sheets.

Lessee, Operating Lease, Liability, Maturity [Table Text Block]

As of December 31, 2019, maturities of operating lease liabilities were as follows:

	CenterPoint Energy		Houston  Electric		CERC
	(in millions)
2020	$	22	$	1	$	6
2021	16		—		4
2022	9		—		4
2023	7		—		3
2024	3		—		2
2025 and beyond	12		—		9
Total lease payments	69		1		28
Less: Interest	6		—		4
Present value of lease liabilities	$	63	$	1	$	24

Schedule of Future Minimum Rental Payments for Operating Leases [Table Text Block]

The following table sets forth information concerning the Registrants’ obligations under non-cancelable long-term operating leases as of December 31, 2018:    

	CenterPoint Energy		Houston  Electric		CERC
	(in millions)
2019	$	6	$	1	$	5
2020	6		—		5
2021	5		—		4
2022	4		—		4
2023	3		—		3
2024 and beyond	12		—		11
Total (1)	$	36	$	1	$	32

(1)

The Merger was completed on February 1, 2019. As such, these amounts are exclusive of Vectren’s leases

Lessor, Operating Lease, Payments to be Received, Maturity [Table Text Block]

As of December 31, 2019, maturities of undiscounted operating lease payments to be received are as follows:

	CenterPoint Energy		Houston  Electric		CERC
	(in millions)
2020	$	3	$	1	$	1
2021	2		—		—
2022	2		—		—
2023	2		—		—
2024	2		—		—
2025 and beyond	10		—		—
Total lease payments to be received	$	21	$	1	$	1

Other Information Related To Leases [Table Text Block]

Other information related to leases is as follows. See Note 20 for information on ROU assets obtained in exchange for operating lease liabilities:

	Year Ended December 31, 2019
	CenterPoint Energy		Houston Electric		CERC
	(in millions)
Operating cash flows from operating leases included in the measurement of lease liabilities	$	25	$	1	$	6

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Unaudited Quarterly Information (Tables)

12 Months Ended

Dec. 31, 2019

Quarterly Financial Information Disclosure [Abstract]

Quarterly Financial Data [Table Text Block]

Summarized quarterly financial data is as follows:

	Year Ended December 31, 2019
	First Quarter		Second Quarter		Third Quarter			Fourth Quarter
	(in millions, except per share amounts)
CenterPoint Energy
Revenues	$	3,531	$	2,798	$	2,742		$	3,230
Operating income	245		287		392			302
Income available to common shareholders	140		165		241			128
Basic earnings per common share (1)	0.28		0.33		0.48			0.25
Diluted earnings per common share (1)	0.28		0.33		0.47			0.25
Houston Electric
Revenues	686		765		859			680
Operating income	81		169		269			99
Net income	27		100		185			44
CERC
Revenues	2,368		1,342		1,126			1,734
Operating income	196		58		23			73
Net income (loss)	138		28		(7		)	53

	Year Ended December 31, 2018
	First Quarter		Second Quarter			Third Quarter			Fourth Quarter
	(in millions, except per share amounts)
CenterPoint Energy
Revenues	$	3,155	$	2,186		$	2,212		$	3,036
Operating income	251		187			226			167
Income (loss) available to common shareholders	165		(75		)	153			90
Basic earnings (loss) per common share (1)	0.38		(0.17		)	0.35			0.18
Diluted earnings (loss) per common share (1)	0.38		(0.17		)	0.35			0.18
Houston Electric
Revenues	755		854			897			728
Operating income	119		181			227			98
Net income	52		101			143			40
CERC (2)
Revenues	2,400		1,328			1,312			2,303
Operating income (loss)	131		22			(7		)	76
Income (loss) from continuing operations	78		(8		)	(35		)	35
Income (loss) from discontinued operations	52		44			44			(2		)
Net income	130		36			9			33

(1) Quarterly earnings (loss) per common share are based on the weighted average number of shares outstanding during the quarter, and the sum of the quarters may not equal annual earnings (loss) per common share.

(2) Amounts have been recast to reflect discontinued operations in all periods presented.

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Related Party Transactions (Houston Electric and CERC) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019		Dec. 31, 2018		Dec. 31, 2017
Related Party Transaction [Line Items]
Capital distribution to parent associated with the Internal Spin (1)		$ 0		$ 0		$ 0
Houston Electric [Member]
Related Party Transaction [Line Items]
Cash dividends paid to parent		376		209		180
Capital distribution to parent associated with the Internal Spin (1)		0		0		0
Houston Electric [Member] | Other, net [Member]
Related Party Transaction [Line Items]
Interest income (expense), net (1)	[1]	18		1		2
Houston Electric [Member] | Operation And Maintenance Expense [Member]
Related Party Transaction [Line Items]
Net affiliate service charges (billings)		(8)		(17)		(9)
Houston Electric [Member] | Operation And Maintenance Expense [Member] | CenterPoint Energy [Member]
Related Party Transaction [Line Items]
Corporate service charges		177		190		188
Houston Electric [Member] | Accounts and notes receivable (payable) - affiliate companies [Member]
Related Party Transaction [Line Items]
Money pool investments (borrowings) (1)	[2]	$ 481
Money Pool Borrowings	[2]			$ (1)
Houston Electric [Member] | Investments [Member]
Related Party Transaction [Line Items]
Weighted average interest rate		1.98%		2.42%
CERC Corp [Member]
Related Party Transaction [Line Items]
Cash dividends paid to parent		$ 120		$ 360		601
Capital distribution to parent associated with the Internal Spin (1)		28	[3],[4]	1,473	[4]	0
CERC Corp [Member] | Other, net [Member]
Related Party Transaction [Line Items]
Interest income (expense), net (1)	[1]	4		0		0
CERC Corp [Member] | Operation And Maintenance Expense [Member]
Related Party Transaction [Line Items]
Net affiliate service charges (billings)		8		17		9
Pipeline construction and repair service charges	[5]	4
CERC Corp [Member] | Operation And Maintenance Expense [Member] | CenterPoint Energy [Member]
Related Party Transaction [Line Items]
Corporate service charges		141		147		128
CERC Corp [Member] | Non-utility revenue [Member]
Related Party Transaction [Line Items]
Natural gas sales	[6]	1
CERC Corp [Member] | Accounts and notes receivable (payable) - affiliate companies [Member]
Related Party Transaction [Line Items]
Money pool investments (borrowings) (1)	[2]	$ 0		$ 114
CERC Corp [Member] | Investments [Member]
Related Party Transaction [Line Items]
Weighted average interest rate		1.98%		2.42%
Additional Paid-in Capital [Member] | Houston Electric [Member]
Related Party Transaction [Line Items]
Contribution From Parent		$ 590		$ 200		0
Additional Paid-in Capital [Member] | CERC Corp [Member]
Related Party Transaction [Line Items]
Contribution From Parent		129		960		38
Capital distribution to parent associated with the Internal Spin (1)		$ (28)		$ (1,473)		$ 0

[1] Interest income is included in Other, net and interest expense is included in Interest and other finance charges on Houston Electric’s and CERC’s respective Statements of Consolidated Income.

[2] Included in Accounts and notes receivable (payable)–affiliated companies in Houston Electric’s and CERC’s Consolidated Balance Sheets.

[3] The capital distribution in 2019 associated with the Internal Spin is a result of the return to accrual for the periods of CERC’s ownership during 2018.

[4] The capital distribution in 2019 associated with the Internal Spin is a result of the return to accrual for the periods of CERC’s ownership during 2018.

[5] Represents charges from Infrastructure Services to CERC’s NGD for the period February 1, 2019 through December 31, 2019.

[6] Represents sales to Indiana Electric from CES for the period February 1, 2019 through December 31, 2019.

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Short Term Borrowings and Long Term Debt Schedule of Debt (Details) $ in Millions		12 Months Ended
		Dec. 31, 2019 USD ($) day		Dec. 31, 2018 USD ($)
Long-term debt:
Unamortized Issuance Costs		$ (22)		$ (13)
Unamortized Discount (Premium), Net		(7)		(2)
Long-term Debt		14,244		8,682
Debt, Current	[1]	868		482
Interest Expense, Related Party		5
Commercial paper issued in connection with the Merger		$ 764
Number of days until commercial paper maturity | day		60
ZENS due 2029 (2)
Long-term debt:
Long-Term	[2]	$ 0		0
Current	[1],[2]	$ 19		24
Debt instrument interest rate		2.00%
Senior notes 2.50% to 7.08% due 2020 to 2049 (3)
Long-term debt:
Long-Term		$ 3,728	[3]	2,000
Current	[1]	100	[3]	0
Variable rate term loan [Member]
Long-term debt:
Long-Term		1,000
Current	[1]	$ 500
Debt instrument interest rate		2.275%
First Mortgage Bonds [Member]
Long-term debt:
Long-Term	[4]	$ 293
Current	[1],[4]	0
Pollution control bonds 5.125% due 2028 (5)
Long-term debt:
Long-Term	[5]	68		68
Current	[1],[5]	0		0
Commercial paper (4)
Long-term debt:
Long-Term	[6]	1,901	[7]	0
Current	[1],[6],[7]	0		0
Other Debt Obligations [Member]
Long-term debt:
Long-Term		18
Current	[1]	$ 18
Parent Company [Member] | Senior notes 2.50% to 7.08% due 2020 to 2049 (3) | Minimum [Member]
Long-term debt:
Debt instrument interest rate		2.50%
Parent Company [Member] | Senior notes 2.50% to 7.08% due 2020 to 2049 (3) | Maximum [Member]
Long-term debt:
Debt instrument interest rate		7.08%
Parent Company [Member] | Variable rate term loan [Member] | Minimum [Member]
Long-term debt:
Debt instrument interest rate		2.275%
Parent Company [Member] | Variable rate term loan [Member] | Maximum [Member]
Long-term debt:
Debt instrument interest rate		2.56%
Parent Company [Member] | First Mortgage Bonds [Member] | Minimum [Member]
Long-term debt:
Debt instrument interest rate		2.19%
Parent Company [Member] | First Mortgage Bonds [Member] | Maximum [Member]
Long-term debt:
Debt instrument interest rate		6.72%
Parent Company [Member] | Pollution control bonds 5.125% due 2028 (5)
Long-term debt:
Long-Term		$ 68
Debt instrument interest rate		5.125%
Amount of debt secured by general mortgage bonds		$ 68		68
VUHI [Member]
Long-term debt:
Notes Payable, Related Parties, Noncurrent		$ 568
Number of days until commercial paper maturity | day		30
VUHI [Member] | Senior notes 3.55% to 6.625% due 2021 to 2047
Long-term debt:
Long-Term		$ 532
Houston Electric [Member]
Long-term debt:
Unamortized Issuance Costs		(27)		(24)
Unamortized Discount (Premium), Net		(15)		(11)
Long-term Debt		4,719		4,258
Debt, Current	[1]	231		458
Houston Electric [Member] | First mortgage bonds 9.15% due 2021
Long-term debt:
Long-Term		102		102
Current	[1]	$ 0		0
Debt instrument interest rate		9.15%
Amount of debt secured by general mortgage bonds		$ 102
Houston Electric [Member] | General mortgage bonds 1.85% to 6.95% due 2021 to 2048
Long-term debt:
Long-Term		3,912		3,212
Current	[1]	0		0
Amount of debt secured by general mortgage bonds		$ 4,000
Houston Electric [Member] | General mortgage bonds 1.85% to 6.95% due 2021 to 2048 | Minimum [Member]
Long-term debt:
Debt instrument interest rate		1.85%
Houston Electric [Member] | General mortgage bonds 1.85% to 6.95% due 2021 to 2048 | Maximum [Member]
Long-term debt:
Debt instrument interest rate		6.95%
Houston Electric [Member] | System restoration bonds 4.243% due 2022
Long-term debt:
Long-Term		$ 134		197
Current	[1]	$ 62		59
Debt instrument interest rate		4.243%
Houston Electric [Member] | Transition bonds 5.302% due 2019
Long-term debt:
Long-Term		$ 0		0
Current	[1]	$ 0		208
Debt instrument interest rate		5.302%
Houston Electric [Member] | Transition bonds 5.234% due 2020
Long-term debt:
Long-Term		$ 0		29
Current	[1]	$ 29		56
Debt instrument interest rate		5.234%
Houston Electric [Member] | Transition bonds 2.161% to 3.028% due 2020 to 2024
Long-term debt:
Long-Term		$ 613		753
Current	[1]	$ 140		135
Houston Electric [Member] | Transition bonds 2.161% to 3.028% due 2020 to 2024 | Minimum [Member]
Long-term debt:
Debt instrument interest rate		2.161%
Houston Electric [Member] | Transition bonds 2.161% to 3.028% due 2020 to 2024 | Maximum [Member]
Long-term debt:
Debt instrument interest rate		3.028%
CERC Corp [Member]
Long-term debt:
Unamortized Issuance Costs	[8]	$ (13)		(15)
Unamortized Discount (Premium), Net	[8]	(11)		(17)
Long-term Debt	[8]	2,546		2,371
Debt, Current	[1],[8]	0		0
CERC Corp [Member] | Commercial paper (4)
Long-term debt:
Long-Term	[6],[8]	377		210
Current	[1],[8]	0		0
CERC Corp [Member] | Senior notes 3.55% to 6.625% due 2021 to 2047
Long-term debt:
Long-Term	[8]	2,193		2,193
Current	[1],[8]	$ 0		$ 0
CERC Corp [Member] | Senior notes 3.55% to 6.625% due 2021 to 2047 | Minimum [Member]
Long-term debt:
Debt instrument interest rate		3.55%
CERC Corp [Member] | Senior notes 3.55% to 6.625% due 2021 to 2047 | Maximum [Member]
Long-term debt:
Debt instrument interest rate		6.625%
Indiana Gas [Member] | Senior notes 3.55% to 6.625% due 2021 to 2047
Long-term debt:
Long-Term		$ 96
VCC [Member]
Long-term debt:
Notes Payable, Related Parties, Noncurrent		$ 191
Vectren [Member] | Senior notes 3.55% to 6.625% due 2021 to 2047 | Minimum [Member]
Long-term debt:
Debt instrument interest rate		3.72%
Vectren [Member] | Senior notes 3.55% to 6.625% due 2021 to 2047 | Maximum [Member]
Long-term debt:
Debt instrument interest rate		7.08%

[1] Includes amounts due or exchangeable within one year of the date noted.

[2] CenterPoint Energy’s ZENS obligation is bifurcated into a debt component and an embedded derivative component. For additional information regarding ZENS, see Note 12(b). As ZENS are exchangeable for cash at any time at the option of the holders, these notes are classified as a current portion of long-term debt.

[3] Includes $532 million of senior notes issued by VUHI and $96 million of senior notes issued by Indiana Gas. The senior notes have stated interest rates that range from 3.72% to 7.08%. The senior notes issued by VUHI are guaranteed by SIGECO, Indiana Gas and VEDO. In connection with the Merger, two of CenterPoint Energy’s acquired wholly-owned subsidiaries, VUHI and VCC, made offers to prepay certain outstanding guaranteed senior notes as required pursuant to certain note purchase agreements previously entered into by VUHI and VCC. In turn, VUHI and VCC borrowed $568 million and $191 million, respectively, from CenterPoint Energy to fund note redemptions of senior notes effected pursuant to these prepayment offers. To fund these prepayments and payments of approximately $5 million of accrued interest, CenterPoint Energy issued approximately $764 million of commercial paper.

[4] The first mortgage bonds issued by SIGECO subject SIGECO’s properties to a lien under the related mortgage indenture.

[5] $68 million and $68 million of these series of debt were secured by general mortgage bonds of Houston Electric as of December 31, 2019 and 2018, respectively. These general mortgage bonds are not reflected in Houston Electric’s consolidated financial statements because of the contingent nature of the obligations.

[6] Classified as long-term debt because the termination date of the facility that backstops the commercial paper is more than one year from the date noted.

[7] Commercial paper issued by VUHI has maturities up to 30 days.

[8] Issued by CERC Corp.

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Income Taxes (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019		Dec. 31, 2018		Dec. 31, 2017
Current income tax expense (benefit):
Federal	$ 48		$ 89		$ 32
State	21		9		9
Total current expense (benefit)	69		98		41
Deferred income tax expense (benefit):
Federal	74		(25)		(806)
State	(5)		73		36
Total deferred expense (benefit)	69		48		(770)
Total income tax expense (benefit)	138		146		(729)
Income tax reconciliation [Abstract]
Income before income taxes	$ 929		$ 514		$ 1,063
Federal statutory income tax rate	21.00%		21.00%		35.00%
Expected federal income tax expense	$ 195		$ 108		$ 372
Increase (decrease) in tax expense resulting from:
State income tax expense, net of federal income tax	36		22		26
State valuation allowance, net of federal income tax	(4)	[1]	11	[2]	3
State law change, net of federal income tax	(21)	[1]	32	[2]	0
Federal income tax rate reduction	0		0		(1,113)	[3]
Excess deferred income tax amortization	(55)	[1]	(24)	[2]	0
Other, net	(13)		(3)		(17)
Total	(57)		38		(1,101)
Total income tax expense (benefit)	$ 138		$ 146		$ (729)
Effective tax rate (in hundredths)	15.00%		28.00%		(69.00%)
Deferred tax assets:
Benefits and compensation	$ 152		$ 160
Regulatory liabilities	447		356
Loss and credit carryforwards	111		84
Asset retirement obligations	89		62
Deferred Tax Assets, Derivative Instruments	34		0
Other	40		29
Valuation allowance	(25)		(18)
Total deferred tax assets	848		673
Deferred tax liabilities:
Property, plant, and equipment	2,656		1,894
Investment in unconsolidated affiliates	1,010		987
Regulatory assets	344		395
Investment in marketable securities and indexed debt	586		478
Indexed debt securities derivative	0		27
Other	180		131
Total deferred tax liabilities	4,776		3,912
Net deferred tax liabilities	3,928		3,239
Reconciliation of Unrecognized Tax Benefits, excluding interest and penalties:
Balance, beginning of year	0
Unrecognized tax benefits assumed through the Merger	9
Decreases related to tax positions of prior years	(1)
Balance, end of year	8		0
State and Local Jurisdiction [Member]
Increase (decrease) in tax expense resulting from:
Federal income tax rate reduction	(21)
Deferred tax liabilities:
Operating loss carryforwards	699
Deferred tax assets tax credit carryforwards	21
Houston Electric [Member]
Current income tax expense (benefit):
Federal	84		109		$ 70
State	20		18		19
Total current expense (benefit)	104		127		89
Deferred income tax expense (benefit):
Federal	(24)		(38)		(98)
Total deferred expense (benefit)	(24)		(38)		(98)
Total income tax expense (benefit)	80		89		(9)
Income tax reconciliation [Abstract]
Income before income taxes	$ 436		$ 425		$ 424
Federal statutory income tax rate	21.00%		21.00%		35.00%
Expected federal income tax expense	$ 92		$ 89		$ 148
Increase (decrease) in tax expense resulting from:
State income tax expense, net of federal income tax	16		14		12
Federal income tax rate reduction	0		0		(158)	[4]
Excess deferred income tax amortization	(21)	[5]	(9)	[6]	0
Other, net	(7)		(5)		(11)
Total	(12)		0		(157)
Total income tax expense (benefit)	$ 80		$ 89		$ (9)
Effective tax rate (in hundredths)	18.00%		21.00%		(2.00%)
Deferred tax assets:
Benefits and compensation	$ 14		$ 17
Regulatory liabilities	195		205
Asset retirement obligations	9		7
Other	7		12
Total deferred tax assets	225		241
Deferred tax liabilities:
Property, plant, and equipment	1,129		1,087
Regulatory assets	126		177
Total deferred tax liabilities	1,255		1,264
Net deferred tax liabilities	1,030		1,023
CERC Corp [Member]
Deferred income tax expense (benefit):
Total deferred expense (benefit)	7		31		$ (224)
Total income tax expense (benefit)	14		22		(265)
Income tax reconciliation [Abstract]
Income before income taxes	226		92		319
Increase (decrease) in tax expense resulting from:
State valuation allowance, net of federal income tax	4
Excess deferred income tax amortization	(18)
Total income tax expense (benefit)	14		22		$ (265)
Deferred tax liabilities:
Operating loss carryforwards	618
CERC Corp [Member] | State and Local Jurisdiction [Member]
Increase (decrease) in tax expense resulting from:
Federal income tax rate reduction	(4)
Deferred tax assets:
Valuation allowance	(15)
Deferred tax liabilities:
Operating loss carryforwards	691
Deferred tax assets tax credit carryforwards	17
Federal Income Tax Rate Prior To TCJA [Member]
Income tax reconciliation [Abstract]
Federal statutory income tax rate					35.00%
Federal Income Tax Rate Prior To TCJA [Member] | Houston Electric [Member]
Income tax reconciliation [Abstract]
Federal statutory income tax rate					35.00%
Federal Income Tax Rate Prior To TCJA [Member] | CERC Corp [Member]
Income tax reconciliation [Abstract]
Federal statutory income tax rate					35.00%
Federal Income Tax Rate After TCJA [Member]
Income tax reconciliation [Abstract]
Federal statutory income tax rate					21.00%
Federal Income Tax Rate After TCJA [Member] | Houston Electric [Member]
Income tax reconciliation [Abstract]
Federal statutory income tax rate					21.00%
Federal Income Tax Rate After TCJA [Member] | CERC Corp [Member]
Income tax reconciliation [Abstract]
Federal statutory income tax rate					21.00%
Continuing Operations [Member] | CERC Corp [Member]
Current income tax expense (benefit):
Federal	0		(9)		$ (31)
State	7		0		(10)
Total current expense (benefit)	7		(9)		(41)
Deferred income tax expense (benefit):
Federal	39		10		(249)
State	(32)		21		25
Total deferred expense (benefit)	7		31		(224)
Total income tax expense (benefit)	14		22		(265)
Income tax reconciliation [Abstract]
Income before income taxes	$ 226		$ 92		$ 319
Federal statutory income tax rate	21.00%		21.00%		35.00%
Expected federal income tax expense	$ 47		$ 19		$ 112
Increase (decrease) in tax expense resulting from:
State income tax expense, net of federal income tax	(12)		5		6
State law change, net of federal income tax	(4)	[7]	0		0
Federal income tax rate reduction	0		0		(396)	[8]
Goodwill impairment	8		0		0
Excess deferred income tax amortization	(18)	[7]	(15)	[9]	0
Other, net	(3)		2		(1)
Total	(33)		3		(377)
Total income tax expense (benefit)	$ 14		$ 22		$ (265)
Effective tax rate (in hundredths)	6.00%		24.00%		(83.00%)
Deferred tax assets:
Benefits and compensation	$ 24		$ 27
Regulatory liabilities	144		150
Loss and credit carryforwards	183		259
Asset retirement obligations	80		54
Other	23		20
Valuation allowance	(15)		(18)
Total deferred tax assets	439		492
Deferred tax liabilities:
Property, plant, and equipment	821		773
Regulatory assets	45		41
Other	43		84
Total deferred tax liabilities	909		898
Net deferred tax liabilities	470		406
Discontinued Operations [Member] | CERC Corp [Member]
Current income tax expense (benefit):
Federal	0		9		$ 31
State	0		4		11
Total current expense (benefit)	0		13		42
Deferred income tax expense (benefit):
Federal	0		29		56
State	0		4		6
Total deferred expense (benefit)	0		33		62
Total income tax expense (benefit)	0		46		104
Income tax reconciliation [Abstract]
Income before income taxes	$ 0		$ 184		$ 265
Federal statutory income tax rate	0.00%		21.00%		35.00%
Expected federal income tax expense	$ 0		$ 39		$ 93
Increase (decrease) in tax expense resulting from:
State income tax expense, net of federal income tax	0		7		11
Total	0		7		11
Total income tax expense (benefit)	$ 0		$ 46		$ 104
Effective tax rate (in hundredths)	0.00%		25.00%		39.00%
State Valuation Allowance, net of Federal Income Taxes [Member] | Continuing Operations [Member] | CERC Corp [Member]
Increase (decrease) in tax expense resulting from:
State valuation allowance, net of federal income tax	$ (4)	[7]	$ 11	[9]	$ 3
Tax Basis Balance Sheet Adjustment [Member] | Continuing Operations [Member] | CERC Corp [Member]
Increase (decrease) in tax expense resulting from:
State valuation allowance, net of federal income tax	0		$ 0		$ 11
Charitable Contribution [Member]
Deferred tax liabilities:
Deferred tax assets tax credit carryforwards	26
Vectren [Member]
Deferred tax liabilities:
Operating loss carryforwards	177
Reconciliation of Unrecognized Tax Benefits, excluding interest and penalties:
Unrecognized tax benefits assumed through the Merger	9
Unrecognized Tax benefit, impacting ETR if recognized	3
Unrecognized Tax Benefits, Reduction Resulting from Lapse of Applicable Statute of Limitations	5
Unrecognized Tax Benefit, including penalties and interest	9
Vectren [Member] | Charitable Contribution [Member]
Deferred tax liabilities:
Deferred tax assets tax credit carryforwards	$ 60

[1] Recognized a $55 million benefit for the amortization of the net regulatory EDIT liability as decreed by regulators in certain jurisdictions, a $21 million net benefit for the impact of state law changes that resulted in the remeasurement of state deferred taxes in those jurisdictions, and $4 million net benefit for the reduction in valuation allowances on certain state net operating losses that are now expected to be realized.

[2] Recognized a $32 million deferred tax expense due to state law changes that resulted in remeasurement of state deferred taxes in those jurisdictions. Also recorded an additional $11 million valuation allowance on certain state net operating loss deferred tax assets that are no longer expected to be utilized prior to expiration after the Internal Spin. These items are partially offset by $24 million of amortization of the net regulatory EDIT liability as decreed by regulators in certain jurisdictions beginning in 2018.

[3] Recognized a $1.1 billion deferred tax benefit from the remeasurement of CenterPoint Energy’s ADFIT liability as a result of the enactment of the TCJA on December 22, 2017, which reduced the U.S. corporate income tax rate from 35% to 21%.

[4] Recognized a $158 million deferred tax benefit from the remeasurement of Houston Electric’s ADFIT liability as a result of the enactment of the TCJA on December 22, 2017, which reduced the U.S. corporate income tax rate from 35% to 21%.

[5] Recognized $21 million of amortization of the net regulatory EDIT liability as decreed by regulators.

[6] Recognized $9 million of amortization of the net regulatory EDIT liability as decreed by regulators in certain jurisdictions beginning in 2018.

[7] Recognized $18 million benefit for the amortization of the net regulatory EDIT liability as decreed by regulators in certain jurisdictions, $4 million net benefit for the impact of state law changes that resulted in the remeasurement of state deferred taxes in those jurisdictions and $4 million net benefit for the reduction in valuation allowances on certain state net operating losses that are now expected to be realized.

[8] Recognized a $396 million deferred tax benefit from the remeasurement of CERC’s ADFIT liability as a result of the enactment of the TCJA on December 22, 2017, which reduced the U.S. corporate income tax rate from 35% to 21%. ASC 740 requires tax impacts of changes in tax laws or rates be reported in continuing operations. Therefore, CERC’s federal income tax benefit generated by the remeasurement of the ADFIT liability for Enable during 2017 and state law changes during 2016 associated with its investment in Enable are reported in continuing operations on CERC’s Statements of Consolidated Income. The ADFIT liability associated with CERC’s investment in Enable is reported as discontinued operations on CERC’s Consolidated Balance Sheets. 

[9] Recorded an additional $11 million valuation allowance on certain state net operating loss deferred tax assets that are no longer expected to be utilized prior to expiration after the Internal Spin. This item is partially offset by $15 million of amortization of the net regulatory EDIT liability in certain jurisdictions as decreed by regulators beginning in 2018.

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Stock-Based Incentive Compensation Plans and Employee Benefit Plans Plan Assets (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019		Dec. 31, 2018		Dec. 31, 2017
Savings Plan [Abstract]
Defined Contribution Plan, Cost	[1]	$ 58		$ 43		$ 41
Postemployment Benefits [Abstract]
Postemployment Benefits, Period Expense		2		3		6
Other Non-Qualified Plans [Abstract]
Benefit expense related to deferred compensation plans		4		$ 3		$ 3
Non-qualified Pension Plan [Member]
Total contributions to the plans during the period		23
Defined Benefit Plan, Expected Future Employer Contributions, Next Fiscal Year		$ 7
Pension Plan [Member]
Discount Rate		3.20%	[2]	4.35%	[2]	3.65%
Plan assets, fair value		$ 2,005		$ 1,516		$ 1,801
Obligation To Return Cash Received As Collateral From Securities Lending,		(61)		(77)
Defined Benefits Plan, Fair Value Of Plan Assets, Excluding Investments Measured at Net Asset Value		1,339		860
Defined Benefit Plan, Contribution by Employer, Qualified Plan		86
Total contributions to the plans during the period		109		$ 69
Defined Benefit Plan, Expected Future Employer Contributions, Next Fiscal Year		76
Defined Benefit Plan, Estimated Future Benefit Payments [Abstract]
Pension benefit payments 2020		180
Pension benefit payments 2021		178
Pension benefit payments 2022		180
Pension benefit payments 2023		181
Pension benefit payments 2024		177
Pension benefit payments 2025 - 2029		$ 824
Other Non-Qualified Plans [Abstract]
Annualized individual discount rates based on time period, minimum		6 months
Annualized individual discount rates based on time period, maximum		99 years
Postretirement Benefits [Member]
Discount Rate		3.25%	[3]	4.35%	[3]	3.60%
Plan assets, fair value		$ 128		$ 114		$ 120
Total contributions to the plans during the period		17		14
Defined Benefit Plan, Expected Future Employer Contributions, Next Fiscal Year		17
Defined Benefit Plan, Estimated Future Benefit Payments [Abstract]
Pension benefit payments 2020		18
Pension benefit payments 2021		18
Pension benefit payments 2022		19
Pension benefit payments 2023		20
Pension benefit payments 2024		21
Pension benefit payments 2025 - 2029		$ 112
Other Non-Qualified Plans [Abstract]
Annualized individual discount rates based on time period, minimum		6 months
Annualized individual discount rates based on time period, maximum		99 years
Fair Value, Inputs, Level 1 [Member] | Pension Plan [Member]
Plan assets, fair value		$ 564		442
Obligation To Return Cash Received As Collateral From Securities Lending,		(61)		(77)
Fair Value, Inputs, Level 2 [Member] | Pension Plan [Member]
Plan assets, fair value		775		418
Obligation To Return Cash Received As Collateral From Securities Lending,		0		0
Fair Value, Inputs, Level 3 [Member] | Pension Plan [Member]
Plan assets, fair value		0		0
Obligation To Return Cash Received As Collateral From Securities Lending,		0		0
U.S. Equity [Member] | Pension Plan [Member]
Plan assets, fair value		69		60
U.S. Equity [Member] | Fair Value, Inputs, Level 1 [Member] | Pension Plan [Member]
Plan assets, fair value		69		60
U.S. Equity [Member] | Fair Value, Inputs, Level 2 [Member] | Pension Plan [Member]
Plan assets, fair value		0		0
U.S. Equity [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Plan [Member]
Plan assets, fair value		0		0
Cash and Cash Equivalents [Member] | Pension Plan [Member]
Plan assets, fair value		(7)		19
Cash and Cash Equivalents [Member] | Fair Value, Inputs, Level 1 [Member] | Pension Plan [Member]
Plan assets, fair value		(7)		19
Cash and Cash Equivalents [Member] | Fair Value, Inputs, Level 2 [Member] | Pension Plan [Member]
Plan assets, fair value		0		0
Cash and Cash Equivalents [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Plan [Member]
Plan assets, fair value		0		0
Investment grade or above [Member] | Pension Plan [Member]
Plan assets, fair value		699		368
Investment grade or above [Member] | Fair Value, Inputs, Level 1 [Member] | Pension Plan [Member]
Plan assets, fair value		0		0
Investment grade or above [Member] | Fair Value, Inputs, Level 2 [Member] | Pension Plan [Member]
Plan assets, fair value		699		368
Investment grade or above [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Plan [Member]
Plan assets, fair value		0		0
Cash received as collateral from securities [Member] | Pension Plan [Member]
Plan assets, fair value		61		77
Cash received as collateral from securities [Member] | Fair Value, Inputs, Level 1 [Member] | Pension Plan [Member]
Plan assets, fair value		61		77
Cash received as collateral from securities [Member] | Fair Value, Inputs, Level 2 [Member] | Pension Plan [Member]
Plan assets, fair value		0		0
Cash received as collateral from securities [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Plan [Member]
Plan assets, fair value		0		0
U.S. treasuries [Member] | Pension Plan [Member]
Plan assets, fair value		232		196
U.S. treasuries [Member] | Fair Value, Inputs, Level 1 [Member] | Pension Plan [Member]
Plan assets, fair value		232		196
U.S. treasuries [Member] | Fair Value, Inputs, Level 2 [Member] | Pension Plan [Member]
Plan assets, fair value		0		0
U.S. treasuries [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Plan [Member]
Plan assets, fair value		0		0
Mortgage backed securities [Member] | Pension Plan [Member]
Plan assets, fair value		8		6
Mortgage backed securities [Member] | Fair Value, Inputs, Level 1 [Member] | Pension Plan [Member]
Plan assets, fair value		0		0
Mortgage backed securities [Member] | Fair Value, Inputs, Level 2 [Member] | Pension Plan [Member]
Plan assets, fair value		8		6
Mortgage backed securities [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Plan [Member]
Plan assets, fair value		0		0
Asset backed securities [Member] | Pension Plan [Member]
Plan assets, fair value		3		1
Asset backed securities [Member] | Fair Value, Inputs, Level 1 [Member] | Pension Plan [Member]
Plan assets, fair value		0		0
Asset backed securities [Member] | Fair Value, Inputs, Level 2 [Member] | Pension Plan [Member]
Plan assets, fair value		3		1
Asset backed securities [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Plan [Member]
Plan assets, fair value		0		0
Municipal bonds [Member] | Pension Plan [Member]
Plan assets, fair value		44		27
Municipal bonds [Member] | Fair Value, Inputs, Level 1 [Member] | Pension Plan [Member]
Plan assets, fair value		0		0
Municipal bonds [Member] | Fair Value, Inputs, Level 2 [Member] | Pension Plan [Member]
Plan assets, fair value		44		27
Municipal bonds [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Plan [Member]
Plan assets, fair value		0		0
Mutual funds [Member] | Pension Plan [Member]
Plan assets, fair value	[4]	270		167
Mutual funds [Member] | Postretirement Benefits [Member]
Plan assets, fair value		$ 128		$ 114
Mutual funds [Member] | International Equity [Member] | Pension Plan [Member]
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage		31.00%		85.00%
Mutual funds [Member] | International Equity [Member] | Postretirement Benefits [Member]
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage		8.00%		7.00%
Mutual funds [Member] | U.S. Equity [Member] | Pension Plan [Member]
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage		49.00%		15.00%
Mutual funds [Member] | U.S. Equity [Member] | Postretirement Benefits [Member]
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage		21.00%		19.00%
Mutual funds [Member] | Real Estate Funds [Member] | Pension Plan [Member]
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage		1.00%		0.00%
Mutual funds [Member] | Fixed Income Funds [Member] | Pension Plan [Member]
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage		19.00%		0.00%
Mutual funds [Member] | Fixed Income Funds [Member] | Postretirement Benefits [Member]
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage		71.00%		74.00%
Mutual funds [Member] | Emerging Market Equity [Member] | Pension Plan [Member]
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage				34.00%
Mutual funds [Member] | Fair Value, Inputs, Level 1 [Member] | Pension Plan [Member]
Plan assets, fair value		$ 270		$ 167
Mutual funds [Member] | Fair Value, Inputs, Level 1 [Member] | Postretirement Benefits [Member]
Plan assets, fair value		128		114
Mutual funds [Member] | Fair Value, Inputs, Level 2 [Member] | Pension Plan [Member]
Plan assets, fair value		0		0
Mutual funds [Member] | Fair Value, Inputs, Level 2 [Member] | Postretirement Benefits [Member]
Plan assets, fair value		0		0
Mutual funds [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Plan [Member]
Plan assets, fair value		0		0
Mutual funds [Member] | Fair Value, Inputs, Level 3 [Member] | Postretirement Benefits [Member]
Plan assets, fair value		0		0
International government bonds [Member] | Pension Plan [Member]
Plan assets, fair value		21		16
International government bonds [Member] | Fair Value, Inputs, Level 1 [Member] | Pension Plan [Member]
Plan assets, fair value		0		0
International government bonds [Member] | Fair Value, Inputs, Level 2 [Member] | Pension Plan [Member]
Plan assets, fair value		21		16
International government bonds [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Plan [Member]
Plan assets, fair value		0		0
Common Collective Trust Funds [Member] | Pension Plan [Member]
Plan assets, fair value	[4],[5]	$ 666		$ 656
Common Collective Trust Funds [Member] | International Equity [Member] | Pension Plan [Member]
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage		29.00%		41.00%
Common Collective Trust Funds [Member] | U.S. Equity [Member] | Pension Plan [Member]
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage		51.00%		5.00%
Common Collective Trust Funds [Member] | Real Estate Funds [Member] | Pension Plan [Member]
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage		6.00%		0.00%
Common Collective Trust Funds [Member] | Fixed Income Funds [Member] | Pension Plan [Member]
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage		14.00%		54.00%
Common Collective Trust Funds [Member] | Emerging Market Equity [Member] | Pension Plan [Member]
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage				4.00%
Benefit Obligation [Member]
Postemployment Benefits [Abstract]
Postemployment benefit obligations		$ 11		$ 11
Other Non-Qualified Plans [Abstract]
Other non-qualified plans benefit obligations deferred compensation		41		42
Benefit obligations related to split-dollar life insurance arrangements		$ 32		36
Minimum [Member] | U.S. Equity [Member] | Pension Plan [Member]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		19.00%
Minimum [Member] | U.S. Equity [Member] | Postretirement Benefits [Member]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		13.00%
Minimum [Member] | International Developed Market Equity [Member] | Pension Plan [Member]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		8.00%
Minimum [Member] | International Developed Market Equity [Member] | Postretirement Benefits [Member]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		3.00%
Minimum [Member] | Real Estate Funds [Member] | Pension Plan [Member]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		3.00%
Minimum [Member] | Fixed Income [Member] | Pension Plan [Member]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		52.00%
Minimum [Member] | Fixed Income [Member] | Postretirement Benefits [Member]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		69.00%
Minimum [Member] | Cash and Cash Equivalents [Member] | Pension Plan [Member]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		0.00%
Minimum [Member] | Cash and Cash Equivalents [Member] | Postretirement Benefits [Member]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		0.00%
Maximum [Member] | U.S. Equity [Member] | Pension Plan [Member]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		29.00%
Maximum [Member] | U.S. Equity [Member] | Postretirement Benefits [Member]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		23.00%
Maximum [Member] | International Developed Market Equity [Member] | Pension Plan [Member]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		18.00%
Maximum [Member] | International Developed Market Equity [Member] | Postretirement Benefits [Member]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		13.00%
Maximum [Member] | Real Estate Funds [Member] | Pension Plan [Member]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		9.00%
Maximum [Member] | Fixed Income [Member] | Pension Plan [Member]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		62.00%
Maximum [Member] | Fixed Income [Member] | Postretirement Benefits [Member]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		79.00%
Maximum [Member] | Cash and Cash Equivalents [Member] | Pension Plan [Member]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		2.00%
Maximum [Member] | Cash and Cash Equivalents [Member] | Postretirement Benefits [Member]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		2.00%
Common Stock [Member] | CenterPoint Energy [Member]
Savings Plan [Abstract]
Number of Common stock held by the savings plan (in shares)		11,051,800
Percentage of investment in common stocks (in hundredths)		13.00%
Defined Contribution Plan, Maximum Limit Of Account Balance In Company Stock, Percentage		25.00%
Houston Electric [Member]
Savings Plan [Abstract]
Defined Contribution Plan, Cost	[1]	$ 18		17		17
Postemployment Benefits [Abstract]
Postemployment Benefits, Period Expense		1		4		1
Other Non-Qualified Plans [Abstract]
Benefit expense related to deferred compensation plans		1		$ 1		$ 1
Houston Electric [Member] | Non-qualified Pension Plan [Member]
Total contributions to the plans during the period		0
Defined Benefit Plan, Expected Future Employer Contributions, Next Fiscal Year		0
Houston Electric [Member] | Pension Plan [Member]
Defined Benefit Plan, Contribution by Employer, Qualified Plan		0
Defined Benefit Plan, Expected Future Employer Contributions, Next Fiscal Year		$ 0
Houston Electric [Member] | Postretirement Benefits [Member]
Discount Rate		3.25%	[3]	4.35%	[3]	3.60%
Plan assets, fair value		$ 101		$ 89		$ 93
Total contributions to the plans during the period		10		9
Defined Benefit Plan, Expected Future Employer Contributions, Next Fiscal Year		9
Defined Benefit Plan, Estimated Future Benefit Payments [Abstract]
Pension benefit payments 2020		8
Pension benefit payments 2021		8
Pension benefit payments 2022		9
Pension benefit payments 2023		10
Pension benefit payments 2024		10
Pension benefit payments 2025 - 2029		$ 54
Other Non-Qualified Plans [Abstract]
Annualized individual discount rates based on time period, minimum		6 months
Annualized individual discount rates based on time period, maximum		99 years
Houston Electric [Member] | Mutual funds [Member] | Postretirement Benefits [Member]
Plan assets, fair value		$ 101		$ 89
Houston Electric [Member] | Mutual funds [Member] | International Equity [Member] | Postretirement Benefits [Member]
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage		8.00%		7.00%
Houston Electric [Member] | Mutual funds [Member] | U.S. Equity [Member] | Postretirement Benefits [Member]
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage		21.00%		19.00%
Houston Electric [Member] | Mutual funds [Member] | Fixed Income Funds [Member] | Postretirement Benefits [Member]
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage		71.00%		74.00%
Houston Electric [Member] | Mutual funds [Member] | Fair Value, Inputs, Level 1 [Member] | Postretirement Benefits [Member]
Plan assets, fair value		$ 101		$ 89
Houston Electric [Member] | Mutual funds [Member] | Fair Value, Inputs, Level 2 [Member] | Postretirement Benefits [Member]
Plan assets, fair value		0		0
Houston Electric [Member] | Mutual funds [Member] | Fair Value, Inputs, Level 3 [Member] | Postretirement Benefits [Member]
Plan assets, fair value		0		0
Houston Electric [Member] | Benefit Obligation [Member]
Postemployment Benefits [Abstract]
Postemployment benefit obligations		3		3
Other Non-Qualified Plans [Abstract]
Other non-qualified plans benefit obligations deferred compensation		8		9
Benefit obligations related to split-dollar life insurance arrangements		$ 1		1
Houston Electric [Member] | Minimum [Member] | U.S. Equity [Member] | Postretirement Benefits [Member]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		13.00%
Houston Electric [Member] | Minimum [Member] | International Developed Market Equity [Member] | Postretirement Benefits [Member]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		3.00%
Houston Electric [Member] | Minimum [Member] | Fixed Income [Member] | Postretirement Benefits [Member]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		69.00%
Houston Electric [Member] | Minimum [Member] | Cash and Cash Equivalents [Member] | Postretirement Benefits [Member]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		0.00%
Houston Electric [Member] | Maximum [Member] | U.S. Equity [Member] | Postretirement Benefits [Member]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		23.00%
Houston Electric [Member] | Maximum [Member] | International Developed Market Equity [Member] | Postretirement Benefits [Member]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		13.00%
Houston Electric [Member] | Maximum [Member] | Fixed Income [Member] | Postretirement Benefits [Member]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		79.00%
Houston Electric [Member] | Maximum [Member] | Cash and Cash Equivalents [Member] | Postretirement Benefits [Member]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		2.00%
Houston Electric [Member] | Common Stock [Member] | CenterPoint Energy [Member]
Savings Plan [Abstract]
Number of Common stock held by the savings plan (in shares)		11,051,800
Percentage of investment in common stocks (in hundredths)		13.00%
Defined Contribution Plan, Maximum Limit Of Account Balance In Company Stock, Percentage		25.00%
CERC Corp [Member]
Savings Plan [Abstract]
Defined Contribution Plan, Cost	[1]	$ 18		18		17
Postemployment Benefits [Abstract]
Postemployment Benefits, Period Expense		1		1		4
Other Non-Qualified Plans [Abstract]
Benefit expense related to deferred compensation plans		0		$ 0		$ 0
CERC Corp [Member] | Non-qualified Pension Plan [Member]
Total contributions to the plans during the period		0
Defined Benefit Plan, Expected Future Employer Contributions, Next Fiscal Year		0
CERC Corp [Member] | Pension Plan [Member]
Defined Benefit Plan, Contribution by Employer, Qualified Plan		0
Defined Benefit Plan, Expected Future Employer Contributions, Next Fiscal Year		$ 0
CERC Corp [Member] | Postretirement Benefits [Member]
Discount Rate		3.25%	[3]	4.35%	[3]	3.60%
Plan assets, fair value		$ 27		$ 25		$ 26
Total contributions to the plans during the period		3		4
Defined Benefit Plan, Expected Future Employer Contributions, Next Fiscal Year		3
Defined Benefit Plan, Estimated Future Benefit Payments [Abstract]
Pension benefit payments 2020		5
Pension benefit payments 2021		4
Pension benefit payments 2022		5
Pension benefit payments 2023		5
Pension benefit payments 2024		6
Pension benefit payments 2025 - 2029		$ 30
Other Non-Qualified Plans [Abstract]
Annualized individual discount rates based on time period, minimum		6 months
Annualized individual discount rates based on time period, maximum		99 years
CERC Corp [Member] | Mutual funds [Member] | Postretirement Benefits [Member]
Plan assets, fair value		$ 27		$ 25
CERC Corp [Member] | Mutual funds [Member] | International Equity [Member] | Postretirement Benefits [Member]
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage		7.00%		6.00%
CERC Corp [Member] | Mutual funds [Member] | U.S. Equity [Member] | Postretirement Benefits [Member]
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage		24.00%		21.00%
CERC Corp [Member] | Mutual funds [Member] | Fixed Income Funds [Member] | Postretirement Benefits [Member]
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage		69.00%		73.00%
CERC Corp [Member] | Mutual funds [Member] | Fair Value, Inputs, Level 1 [Member] | Postretirement Benefits [Member]
Plan assets, fair value		$ 27		$ 25
CERC Corp [Member] | Mutual funds [Member] | Fair Value, Inputs, Level 2 [Member] | Postretirement Benefits [Member]
Plan assets, fair value		0		0
CERC Corp [Member] | Mutual funds [Member] | Fair Value, Inputs, Level 3 [Member] | Postretirement Benefits [Member]
Plan assets, fair value		0		0
CERC Corp [Member] | Benefit Obligation [Member]
Postemployment Benefits [Abstract]
Postemployment benefit obligations		7		7
Other Non-Qualified Plans [Abstract]
Other non-qualified plans benefit obligations deferred compensation		3		3
Benefit obligations related to split-dollar life insurance arrangements		$ 0		$ 0
CERC Corp [Member] | Minimum [Member] | U.S. Equity [Member] | Postretirement Benefits [Member]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		15.00%
CERC Corp [Member] | Minimum [Member] | International Developed Market Equity [Member] | Postretirement Benefits [Member]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		2.00%
CERC Corp [Member] | Minimum [Member] | Fixed Income [Member] | Postretirement Benefits [Member]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		68.00%
CERC Corp [Member] | Minimum [Member] | Cash and Cash Equivalents [Member] | Postretirement Benefits [Member]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		0.00%
CERC Corp [Member] | Maximum [Member] | U.S. Equity [Member] | Postretirement Benefits [Member]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		25.00%
CERC Corp [Member] | Maximum [Member] | International Developed Market Equity [Member] | Postretirement Benefits [Member]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		12.00%
CERC Corp [Member] | Maximum [Member] | Fixed Income [Member] | Postretirement Benefits [Member]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		78.00%
CERC Corp [Member] | Maximum [Member] | Cash and Cash Equivalents [Member] | Postretirement Benefits [Member]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		2.00%
CERC Corp [Member] | Common Stock [Member] | CenterPoint Energy [Member]
Savings Plan [Abstract]
Number of Common stock held by the savings plan (in shares)		11,051,800
Percentage of investment in common stocks (in hundredths)		13.00%
Defined Contribution Plan, Maximum Limit Of Account Balance In Company Stock, Percentage		25.00%

[1] Amounts presented in the table above are included in Operation and maintenance expense in the Registrants’ respective Statements of Consolidated Income and shown prior to any amounts capitalized.

[2] The discount rate assumption was determined by matching the projected cash flows of CenterPoint Energy’s plans against a hypothetical yield curve of high-quality corporate bonds represented by a series of annualized individual discount rates from one-half to 99 years.

[3] The discount rate assumption was determined by matching the projected cash flows of the plans against a hypothetical yield curve of high-quality corporate bonds represented by a series of annualized individual discount rates from one-half to 99 years.

[4] The amounts invested in mutual funds and common collective trust funds were allocated as follows:   As of December 31,   2019   2018   Mutual Funds   Common Collective Trust Funds   Mutual Funds   Common Collective Trust Funds International equities (1) 31 %   29 %   85 %   41 % U.S. equities 49 %   51 %   15 %   5 % Real estate 1 %   6 %   — %   — % Fixed income 19 %   14 %   — %   54 %

(1) The amounts invested in international equities for 2018 include allocations of 34% in mutual funds and 4% in common collective trust funds,which were previously reported as allocations in emerging market equities.

[5] Represents investments in common collective trust funds.

XML

Fair Value Measurements (Details) $ in Millions		12 Months Ended
		Dec. 31, 2019 USD ($)		Dec. 31, 2018 USD ($)		Dec. 31, 2017 USD ($)
Assets
Natural gas derivatives (3)(4)		$ 47		$ 57
Total derivative assets, netting adjustment	[1]	(98)		(82)
Total assets		1,068		747
Liabilities
Total derivative liabilities, netting adjustment	[1]	(161)		(101)
Total liabilities		996		732
Fair value measurement using significant unobservable input (level 3) reconciliation [Roll Forward]
Beginning balance		30	[2]	(622)	[2]	$ (704)
Total gains		17		30		96
Total settlements		(22)		(39)		(11)
Transfers into Level 3		(1)		5		14
Transfers out of Level 3 (1)	[3]	(6)		656		(17)
Ending balance (2)	[2]	18		30		(622)
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the reporting date (3)		12		18		87
Estimated Fair Value of Financial Instruments
Goodwill impairment		48		0		0
Carrying amount [Member]
Estimated Fair Value of Financial Instruments
Long-term debt, including current maturities	[4]	15,093		9,140
Fair value [Member]
Estimated Fair Value of Financial Instruments
Long-term debt, including current maturities	[4]	16,067		9,308
Natural gas [Member]
Liabilities
Derivative fair value offsets, net		63		19
Fair Value, Inputs, Level 1 [Member]
Assets
Total assets		874		609
Liabilities
Total liabilities		13		24
Fair Value, Inputs, Level 2 [Member]
Assets
Total assets		250		173
Liabilities
Total liabilities		1,120		792
Fair Value, Inputs, Level 3 [Member]
Assets
Total assets		42		47
Liabilities
Total liabilities		$ 24		17
Fair Value, Inputs, Level 3 [Member] | Forward Contracts [Member] | Minimum [Member]
Fair Value, assets and liabilities measured on recurring basis, financial statement captions
Fair value inputs (price per MMBtu)		1.44
Fair Value, Inputs, Level 3 [Member] | Forward Contracts [Member] | Maximum [Member]
Fair Value, assets and liabilities measured on recurring basis, financial statement captions
Fair value inputs (price per MMBtu)		5.20
Fair Value, Measurements, Recurring [Member]
Assets
Corporate equities		$ 825		542
Investments, including money market funds (2)	[5]	49		66
Fair Value, Measurements, Recurring [Member] | Natural gas [Member]
Assets
Natural gas derivative netting adjustment	[1],[6]	(98)		(82)
Natural gas derivatives (3)(4)	[6]	194		138
Liabilities
Derivative liabilities, netting adjustment	[1],[6]	(161)		(101)
Derivative liabilities	[6]	80		107
Fair Value, Measurements, Recurring [Member] | IDS Derivative [Member]
Liabilities
Derivative liabilities, netting adjustment		0		0
Derivative liabilities		893		601
Fair Value, Measurements, Recurring [Member] | Interest Rate Contract [Member]
Liabilities
Derivative liabilities		10		24
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Assets
Corporate equities		825		542
Investments, including money market funds (2)	[5]	49		66
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Natural gas [Member]
Assets
Natural gas derivatives (3)(4)	[6],[7]	0		0
Liabilities
Derivative liabilities	[6],[7]	0		0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | IDS Derivative [Member]
Liabilities
Derivative liabilities		0		0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Interest Rate Contract [Member]
Liabilities
Derivative liabilities		0		24
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Assets
Corporate equities		0		0
Investments, including money market funds (2)	[5]	0		0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Natural gas [Member]
Assets
Natural gas derivatives (3)(4)	[6]	250		173
Liabilities
Derivative liabilities	[6]	217		191
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | IDS Derivative [Member]
Liabilities
Derivative liabilities		893		601
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Interest Rate Contract [Member]
Liabilities
Derivative liabilities		10		0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]
Assets
Corporate equities		0		0
Investments, including money market funds (2)	[5]	0		0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Natural gas [Member]
Assets
Natural gas derivatives (3)(4)	[6]	42		47
Liabilities
Derivative liabilities	[6]	24		17
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | IDS Derivative [Member]
Liabilities
Derivative liabilities		0		0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Interest Rate Contract [Member]
Liabilities
Derivative liabilities		0		0
Houston Electric [Member]
Assets
Total derivative assets, netting adjustment		0		0
Total assets		32		48
Liabilities
Total derivative liabilities, netting adjustment		0		0
Total liabilities		0		24
Houston Electric [Member] | Carrying amount [Member]
Estimated Fair Value of Financial Instruments
Long-term debt, including current maturities	[4]	4,950		4,717
Houston Electric [Member] | Fair value [Member]
Estimated Fair Value of Financial Instruments
Long-term debt, including current maturities	[4]	5,457		4,770
Houston Electric [Member] | Fair Value, Inputs, Level 1 [Member]
Assets
Total assets		32		48
Liabilities
Total liabilities		0		24
Houston Electric [Member] | Fair Value, Inputs, Level 2 [Member]
Assets
Total assets		0		0
Liabilities
Total liabilities		0		0
Houston Electric [Member] | Fair Value, Inputs, Level 3 [Member]
Assets
Total assets		0		0
Liabilities
Total liabilities		0		0
Houston Electric [Member] | Fair Value, Measurements, Recurring [Member]
Assets
Investments, including money market funds (2)	[5]	32		48
Houston Electric [Member] | Fair Value, Measurements, Recurring [Member] | Interest Rate Contract [Member]
Liabilities
Derivative liabilities		0		24
Houston Electric [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Assets
Investments, including money market funds (2)	[5]	32		48
Houston Electric [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Interest Rate Contract [Member]
Liabilities
Derivative liabilities		0		24
Houston Electric [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Assets
Investments, including money market funds (2)	[5]	0		0
Houston Electric [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Interest Rate Contract [Member]
Liabilities
Derivative liabilities		0		0
Houston Electric [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]
Assets
Investments, including money market funds (2)	[5]	0		0
Houston Electric [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Interest Rate Contract [Member]
Liabilities
Derivative liabilities		0		0
CERC Corp [Member]
Assets
Natural gas derivatives (3)(4)		47		57
Total derivative assets, netting adjustment	[1]	(98)		(82)
Total assets		207		152
Liabilities
Total derivative liabilities, netting adjustment	[1]	(161)		(101)
Total liabilities		71		107
Fair value measurement using significant unobservable input (level 3) reconciliation [Roll Forward]
Beginning balance		30	[2]	46	[2]	13
Total gains		17		30		47
Total settlements		(22)		(39)		(11)
Transfers into Level 3		(1)		5		14
Transfers out of Level 3 (1)	[3]	(6)		(12)		(17)
Ending balance (2)	[2]	18		30		46
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the reporting date (3)		12		18		38
Estimated Fair Value of Financial Instruments
Goodwill impairment		48		0		$ 0
CERC Corp [Member] | Carrying amount [Member]
Estimated Fair Value of Financial Instruments
Long-term debt, including current maturities		2,546		2,371
CERC Corp [Member] | Fair value [Member]
Estimated Fair Value of Financial Instruments
Long-term debt, including current maturities		2,803		2,488
CERC Corp [Member] | Natural gas [Member]
Liabilities
Derivative fair value offsets, net		63		19
CERC Corp [Member] | Fair Value, Inputs, Level 1 [Member]
Assets
Total assets		13		14
Liabilities
Total liabilities		13		0
CERC Corp [Member] | Fair Value, Inputs, Level 2 [Member]
Assets
Total assets		250		173
Liabilities
Total liabilities		195		191
CERC Corp [Member] | Fair Value, Inputs, Level 3 [Member]
Assets
Total assets		42		47
Liabilities
Total liabilities		$ 24		17
CERC Corp [Member] | Fair Value, Inputs, Level 3 [Member] | Forward Contracts [Member] | Minimum [Member]
Fair Value, assets and liabilities measured on recurring basis, financial statement captions
Fair value inputs (price per MMBtu)		1.44
CERC Corp [Member] | Fair Value, Inputs, Level 3 [Member] | Forward Contracts [Member] | Maximum [Member]
Fair Value, assets and liabilities measured on recurring basis, financial statement captions
Fair value inputs (price per MMBtu)		5.20
CERC Corp [Member] | Fair Value, Measurements, Recurring [Member]
Assets
Corporate equities		$ 2		2
Investments, including money market funds (2)	[5]	11		11
CERC Corp [Member] | Fair Value, Measurements, Recurring [Member] | Natural gas [Member]
Assets
Natural gas derivative netting adjustment	[1],[6]	(98)		(82)
Natural gas derivatives (3)(4)	[6]	194		138
Liabilities
Derivative liabilities, netting adjustment	[1],[6]	(161)		(101)
Derivative liabilities	[6]	58		107
CERC Corp [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Assets
Corporate equities		2		2
Investments, including money market funds (2)	[5]	11		11
CERC Corp [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Natural gas [Member]
Assets
Natural gas derivatives (3)(4)	[6],[7]	0		0
Liabilities
Derivative liabilities	[6],[7]	0		0
CERC Corp [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Assets
Corporate equities		0		0
Investments, including money market funds (2)	[5]	0		0
CERC Corp [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Natural gas [Member]
Assets
Natural gas derivatives (3)(4)	[6]	250		173
Liabilities
Derivative liabilities	[6]	195		191
CERC Corp [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]
Assets
Corporate equities		0		0
Investments, including money market funds (2)	[5]	0		0
CERC Corp [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Natural gas [Member]
Assets
Natural gas derivatives (3)(4)	[6]	42		47
Liabilities
Derivative liabilities	[6]	24		17
Natural gas inventory [Member] | Fair Value, Measurements, Recurring [Member]
Assets
Hedged portion of natural gas inventory		0		1
Liabilities
Fair Value Hedge Liabilities		13		0
Natural gas inventory [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Assets
Hedged portion of natural gas inventory		0		1
Liabilities
Fair Value Hedge Liabilities		13		0
Natural gas inventory [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Assets
Hedged portion of natural gas inventory		0		0
Liabilities
Fair Value Hedge Liabilities		0		0
Natural gas inventory [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]
Assets
Hedged portion of natural gas inventory		0		0
Liabilities
Fair Value Hedge Liabilities		0		0
Natural gas inventory [Member] | CERC Corp [Member] | Fair Value, Measurements, Recurring [Member]
Assets
Hedged portion of natural gas inventory		0		1
Liabilities
Fair Value Hedge Liabilities		13		0
Natural gas inventory [Member] | CERC Corp [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Assets
Hedged portion of natural gas inventory		0		1
Liabilities
Fair Value Hedge Liabilities		13		0
Natural gas inventory [Member] | CERC Corp [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Assets
Hedged portion of natural gas inventory		0		0
Liabilities
Fair Value Hedge Liabilities		0		0
Natural gas inventory [Member] | CERC Corp [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]
Assets
Hedged portion of natural gas inventory		0		0
Liabilities
Fair Value Hedge Liabilities		0		$ 0
Energy Services [Member]
Estimated Fair Value of Financial Instruments
Goodwill impairment		48
Energy Services [Member] | CERC Corp [Member]
Estimated Fair Value of Financial Instruments
Goodwill impairment		$ 48

[1] Amounts represent the impact of legally enforceable master netting arrangements that allow CenterPoint Energy and CERC to settle positive and negative positions and also include cash collateral posted with the same counterparties as follows:   December 31, 2019   December 31, 2018   CenterPoint Energy   CERC   CenterPoint Energy   CERC   (in millions) Cash collateral posted with the same counterparties $ 63
  $ 63
  $ 19
  $ 19

[2] CenterPoint Energy and CERC did not have significant Level 3 purchases or sales during any of the years ended December 31, 2019, 2018 or 2017.

[3] During 2018, CenterPoint Energy transferred its indexed debt securities derivative from Level 3 to Level 2 to reflect changes in the significance of the unobservable inputs used in the valuation.

[4] Includes Securitization Bond debt.

[5] Amounts are included in Prepaid and Other Current Assets and Other Assets in the Consolidated Balance Sheets.

[6] Natural gas derivatives include no material amounts related to physical forward transactions with Enable.

[7] Level 1 natural gas derivatives include exchange-traded derivatives cleared by the CME, which deems that financial instruments cleared by the CME are settled daily in connection with posted cash payments. As a result of this exchange rule, CME-related derivatives are considered to have no fair value at the balance sheet date for financial reporting purposes, and are presented in Level 1 net of posted cash; however, the derivatives remain outstanding and subject to future commodity price fluctuations until they are settled in accordance with their contractual terms. Derivative transactions cleared on exchanges other than the CME (e.g., the Intercontinental Exchange or ICE) continue to be reported on a gross basis.

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Unaudited Quarterly Information (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended																12 Months Ended
	Dec. 31, 2019		Sep. 30, 2019		Jun. 30, 2019		Mar. 31, 2019		Dec. 31, 2018		Sep. 30, 2018		Jun. 30, 2018		Mar. 31, 2018		Dec. 31, 2019		Dec. 31, 2018		Dec. 31, 2017
Revenues	$ 3,230		$ 2,742		$ 2,798		$ 3,531		$ 3,036		$ 2,212		$ 2,186		$ 3,155		$ 12,301		$ 10,589		$ 9,614
Operating income (loss)	302		392		287		245		167		226		187		251		1,226		831		1,136
Income (loss) available to common shareholders	$ 128		$ 241		$ 165		$ 140		$ 90		$ 153		$ (75)		$ 165		$ 674	[1]	$ 333	[1]	$ 1,792	[1]
Basic earnings per common share (1)	$ 0.25	[2]	$ 0.48	[2]	$ 0.33	[2]	$ 0.28	[2]	$ 0.18	[2]	$ 0.35	[2]	$ (0.17)	[2]	$ 0.38	[2]	$ 1.34		$ 0.74		$ 4.16
Diluted earnings per common share (1)	$ 0.25	[2]	$ 0.47	[2]	$ 0.33	[2]	$ 0.28	[2]	$ 0.18	[2]	$ 0.35	[2]	$ (0.17)	[2]	$ 0.38	[2]	$ 1.33		$ 0.74		$ 4.13
Net income																	$ 791		$ 368		$ 1,792
Houston Electric [Member]
Revenues	$ 680		$ 859		$ 765		$ 686		$ 728		$ 897		$ 854		$ 755		2,990		3,234		2,998
Operating income (loss)	99		269		169		81		98		227		181		119		618		625		637
Net income	44		185		100		27		40		143		101		52		356		336		433
CERC Corp [Member]
Revenues	1,734		1,126		1,342		2,368		2,303	[3]	1,312	[3]	1,328	[3]	2,400	[3]	6,570		7,343		6,603
Operating income (loss)	73		23		58		196		76	[3]	(7)	[3]	22	[3]	131	[3]	350		222		467
Income (loss) from continuing operations									35	[3]	(35)	[3]	(8)	[3]	78	[3]	212		70		584
Income (loss) from discontinued operations, net of tax									(2)	[3]	44	[3]	44	[3]	52	[3]	0		138		161
Net income	$ 53		$ (7)		$ 28		$ 138		$ 33	[3]	$ 9	[3]	$ 36	[3]	$ 130	[3]	$ 212		$ 208		$ 745

[1] Income available to common shareholders for the year ended December 31, 2019 includes net income from businesses acquired in the Merger of $190 million. See Note 4. Income available to common shareholders for the year ended December 31, 2017 includes a reduction in income tax expense of $1,113 million due to tax reform. See Note 15 for further discussion of the impacts of the TCJA.

[2] Quarterly earnings (loss) per common share are based on the weighted average number of shares outstanding during the quarter, and the sum of the quarters may not equal annual earnings (loss) per common share.

[3] Amounts have been recast to reflect discontinued operations in all periods presented.

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Derivative Instruments

12 Months Ended

Dec. 31, 2019

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments [Text Block]

Derivative Instruments

The Registrants are exposed to various market risks. These risks arise from transactions entered into in the normal course of business. The Registrants utilize derivative instruments such as physical forward contracts, swaps and options to mitigate the impact of changes in commodity prices, weather and interest rates on operating results and cash flows.

(a) Non-Trading Activities

Commodity Derivative Instruments (CenterPoint Energy and CERC). CenterPoint Energy, through its Indiana utilities, and CERC, through CES, enter into certain derivative instruments to mitigate the effects of commodity price movements. Certain financial instruments used to hedge portions of the natural gas inventory of the Energy Services reportable segment are designated as fair value hedges for accounting purposes. Outstanding derivative instruments designated as economic hedges at the Indiana Utilities hedge long-term variable rate natural gas purchases. The Indiana Utilities have authority to refund and recover mark-to-market gains and losses associated with hedging natural gas purchases, and thus the gains and losses on derivatives are deferred in a regulatory liability or asset. All other financial instruments do not qualify or are not designated as cash flow or fair value hedges.

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. The transaction is expected to close in the second quarter of 2020. For further information, see Notes 6 and 23.

Interest Rate Risk Derivative Instruments. From time to time, the Registrants may enter into interest rate derivatives that are designated as economic or cash flow hedges. The objective of these hedges is to offset risk associated with interest rates borne by the Registrants in connection with an anticipated future fixed rate debt offering or other exposure to variable rate debt. The Indiana Utilities have authority to refund and recover mark-to-market gains and losses associated with hedging financing activity, and thus the gains and losses on derivatives are deferred in a regulatory liability or asset. For the impacts of cash flow hedges to Accumulated other comprehensive income, see Note 13.

The table below summarizes the Registrants’ outstanding interest rate hedging activity:

	December 31, 2019				December 31, 2018
Hedging Classification	Notional Principal
	CenterPoint  Energy (1)		Houston  Electric		CenterPoint  Energy		Houston  Electric
	(in millions)
Economic hedge	$	84	$	—	$	—	$	—
Cash flow hedge	—		—		450		450

(1) Relates to interest rate derivative instruments at SIGECO.

Weather Hedges (CenterPoint Energy and CERC). CenterPoint Energy and CERC have weather normalization or other rate mechanisms that largely mitigate the impact of weather on NGD in Arkansas, Indiana, Louisiana, Mississippi, Minnesota, Ohio and Oklahoma, as applicable. CenterPoint Energy’s and CERC’s NGD in Texas and CenterPoint Energy’s electric operations in Texas and Indiana do not have such mechanisms, although fixed customer charges are historically higher in Texas for NGD compared to its other jurisdictions. As a result, fluctuations from normal weather may have a positive or negative effect on CenterPoint Energy’s and CERC’s NGD’s results in Texas and on CenterPoint Energy’s electric operations’ results in its Texas and Indiana service territories.

CenterPoint Energy and CERC, as applicable, enter into winter season weather hedges from time to time for certain NGD jurisdictions and electric operations’ service territory to mitigate the effect of fluctuations from normal weather on results of operations and cash flows. These weather hedges are based on heating degree days at 10-year normal weather. Houston Electric and Indiana Electric do not enter into weather hedges.

The tables below summarizes CenterPoint Energy’s and CERC’s weather hedge gain (loss) activity:

CenterPoint Energy

				Year Ended December 31,
Texas Operations	Winter Season	Bilateral Cap		2019		2018			2017
		(in millions)
NGD	2019 – 2020	$	8	$	2	$	—		$	—
NGD	2018 – 2019	9		—		—			—
NGD	2017 – 2018	8		—		(2		)	—
Electric operations	2019 – 2020	7		3		—			—
Electric operations	2018 – 2019	8		3		—			—
Electric operations	2017 – 2018	9		—		(2		)	—
Electric operations	2016 – 2017	9		—		—			(1		)
Total CenterPoint Energy (1)				$	8	$	(4	)	$	(1	)

CERC

				Year Ended December 31,
Texas Operations	Winter Season	Bilateral Cap		2019		2018			2017
		(in millions)
NGD	2019 – 2020	$	8	$	2	$	—		$	—
NGD	2018 – 2019	9		—		—			—
NGD	2017 – 2018	8		—		(2		)	—
Total CERC (1)				$	2	$	(2	)	$	—

(1) Weather hedge gains (losses) are recorded in Revenues in the Statements of Consolidated Income.

(b) Derivative Fair Values and Income Statement Impacts

The following tables present information about derivative instruments and hedging activities. The first three tables provide a balance sheet overview of Derivative Assets and Liabilities as of December 31, 2019 and 2018, while the last two tables provide a breakdown of the related income statement impacts for the years ending December 31, 2019, 2018 and 2017.

Fair Value of Derivative Instruments and Hedged Items

CenterPoint Energy

		December 31, 2019				December 31, 2018
	Balance Sheet Location	Derivative Assets Fair Value		Derivative Liabilities Fair Value		Derivative Assets Fair Value		Derivative Liabilities Fair Value
		(in millions)
Derivatives designated as cash flow hedges:
Interest rate derivatives	Current Liabilities: Non-trading derivative liabilities	$	—	$	—	$	—	$	24
Derivatives designated as fair value hedges:
Natural gas derivatives (1) (2) (3)	Current Liabilities: Non-trading derivative liabilities	12		—		1		7
Derivatives not designated as hedging instruments:
Natural gas derivatives (1) (2) (3)	Current Assets: Non-trading derivative assets	139		3		103		3
Natural gas derivatives (1) (2) (3)	Other Assets: Non-trading derivative assets	58		—		38		—
Natural gas derivatives (1) (2) (3)	Current Liabilities: Non-trading derivative liabilities	73		184		62		173
Natural gas derivatives (1) (2) (3)	Other Liabilities: Non-trading derivative liabilities	10		54		16		25
Interest rate derivatives	Other Liabilities	—		10		—		—
Indexed debt securities derivative	Current Liabilities	—		893		—		601
Total CenterPoint Energy		$	292	$	1,144	$	220	$	833

(1) The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling 2,226 Bcf or a net 374 Bcf long position and 1,674 Bcf or a net 140 Bcf long position as of December 31, 2019 and 2018, respectively. Certain natural gas contracts hedge basis risk only and lack a fixed price exposure.

(2) Natural gas contracts are presented on a net basis in CenterPoint Energy’s Consolidated Balance Sheets as they are subject to master netting arrangements. This netting applies to all undisputed amounts due or past due and causes derivative assets (liabilities) to be ultimately presented net in a liability (asset) account within CenterPoint Energy’s Consolidated Balance Sheets. The net of total non-trading natural gas derivative assets and liabilities is detailed in the Offsetting of Natural Gas Derivative Assets and Liabilities table below.

(3) Derivative Assets and Derivative Liabilities include no material amounts related to physical forward transactions with Enable.

Houston Electric

		December 31, 2019				December 31, 2018
	Balance Sheet Location	Derivative Assets Fair Value		Derivative Liabilities Fair Value		Derivative Assets Fair Value		Derivative Liabilities Fair Value
		(in millions)
Derivatives designated as cash flow hedges:
Interest rate derivatives	Current Liabilities: Non-trading derivative liabilities	$	—	$	—	$	—	$	24
Total Houston Electric		$	—	$	—	$	—	$	24

CERC

		December 31, 2019				December 31, 2018
	Balance Sheet Location	Derivative Assets Fair Value		Derivative Liabilities Fair Value		Derivative Assets Fair Value		Derivative Liabilities Fair Value
		(in millions)
Derivatives designated as fair value hedges:
Natural gas derivatives (1) (2) (3)	Current Liabilities: Non-trading derivative liabilities	$	12	$	—	$	1	$	7
Derivatives not designated as hedging instruments:
Natural gas derivatives (1) (2) (3)	Current Assets: Non-trading derivative assets	139		3		103		3
Natural gas derivatives (1) (2) (3)	Other Assets: Non-trading derivative assets	58		—		38		—
Natural gas derivatives (1) (2) (3)	Current Liabilities: Non-trading derivative liabilities	73		177		62		173
Natural gas derivatives (1) (2) (3)	Other Liabilities: Non-trading derivative liabilities	10		39		16		25
Total CERC		$	292	$	219	$	220	$	208

(1) The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling 2,226 Bcf or a net 374 Bcf long position and 1,674 Bcf or a net 140 Bcf long position as of December 31, 2019 and 2018, respectively. Certain natural gas contracts hedge basis risk only and lack a fixed price exposure.

(2) Natural gas contracts are presented on a net basis in CERC’s Consolidated Balance Sheets as they are subject to master netting arrangements. This netting applies to all undisputed amounts due or past due and causes derivative assets (liabilities) to be ultimately presented net in a liability (asset) account within CERC’s Consolidated Balance Sheets. The net of total non-trading natural gas derivative assets and liabilities is detailed in the Offsetting of Natural Gas Derivative Assets and Liabilities table below.

(3) Derivative Assets and Derivative Liabilities include no material amounts related to physical forward transactions with Enable.

Cumulative Basis Adjustment for Fair Value Hedges (CenterPoint Energy and CERC)

CenterPoint Energy
		December 31, 2019					December 31, 2018
	Balance Sheet Location	Carrying Amount of Hedged Assets/(Liabilities)		Cumulative Amount of Fair Value Hedging Adjustment Included in the Carrying Amount of Hedged Item			Carrying Amount of Hedged Assets/(Liabilities)		Cumulative Amount of Fair Value Hedging Adjustment Included in the Carrying Amount of Hedged Item
		(in millions)
Hedged items in fair value hedge relationship:
Natural gas inventory	Current Assets: Natural gas inventory	$	47	$	(13	)	$	57	$	1
Total CenterPoint Energy		$	47	$	(13	)	$	57	$	1

CERC
		December 31, 2019					December 31, 2018
	Balance Sheet Location	Carrying Amount of Hedged Assets/(Liabilities)		Cumulative Amount of Fair Value Hedging Adjustment Included in the Carrying Amount of Hedged Item			Carrying Amount of Hedged Assets/(Liabilities)		Cumulative Amount of Fair Value Hedging Adjustment Included in the Carrying Amount of Hedged Item
		(in millions)
Hedged items in fair value hedge relationship:
Natural gas inventory	Current Assets: Natural gas inventory	$	47	$	(13	)	$	57	$	1
Total CERC		$	47	$	(13	)	$	57	$	1

Offsetting of Natural Gas Derivative Assets and Liabilities (CenterPoint Energy and CERC)

CenterPoint Energy
	December 31, 2019									December 31, 2018
	Gross Amounts Recognized (1)			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amount Presented in the Consolidated Balance Sheets (2)			Gross Amounts Recognized (1)			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amount Presented in the Consolidated Balance Sheets (2)
	(in millions)
Current Assets: Non-trading derivative assets	$	224		$	(88	)	$	136		$	166		$	(66	)	$	100
Other Assets: Non-trading derivative assets	68			(10		)	58			54			(16		)	38
Current Liabilities: Non-trading derivative liabilities	(187		)	136			(51		)	(183		)	81			(102		)
Other Liabilities: Non-trading derivative liabilities	(54		)	25			(29		)	(25		)	20			(5		)
Total CenterPoint Energy	$	51		$	63		$	114		$	12		$	19		$	31

CERC
	December 31, 2019									December 31, 2018
	Gross Amounts Recognized (1)			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amount Presented in the Consolidated Balance Sheets (2)			Gross Amounts Recognized (1)			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amount Presented in the Consolidated Balance Sheets (2)
	(in millions)
Current Assets: Non-trading derivative assets	$	224		$	(88	)	$	136		$	166		$	(66	)	$	100
Other Assets: Non-trading derivative assets	68			(10		)	58			54			(16		)	38
Current Liabilities: Non-trading derivative liabilities	(180		)	136			(44		)	(183		)	81			(102		)
Other Liabilities: Non-trading derivative liabilities	(39		)	25			(14		)	(25		)	20			(5		)
Total CERC	$	73		$	63		$	136		$	12		$	19		$	31

(1) Gross amounts recognized include some derivative assets and liabilities that are not subject to master netting arrangements.

(2) The derivative assets and liabilities on the Registrant’s respective Consolidated Balance Sheets exclude accounts receivable or accounts payable that, should they exist, could be used as offsets to these balances in the event of a default.

Income Statement Impact of Hedge Accounting Activity (CenterPoint Energy and CERC)

CenterPoint Energy	Year Ended December 31,
	2019			2018			2017
	Location and Amount of Gain (Loss) recognized in Income on Hedging Relationship (1)
	Non-utility cost of revenues, including natural gas
	(in millions)
Total amounts presented in the statements of income in which the effects of hedges are recorded	$	4,029		$	4,364		$	3,785
Gain (loss) on fair value hedging relationships:
Commodity contracts:
Hedged items - Natural gas inventory	(14		)	(13		)	14
Derivatives designated as hedging instruments	14			13			(14		)
Amounts excluded from effectiveness testing recognized in earnings immediately	(213		)	(149		)	(67		)

(1) Income statement impact associated with cash flow hedge activity is related to gains and losses reclassified from Accumulated other comprehensive income into income. Amounts are immaterial for the years ended December 31, 2019, 2018 and 2017, respectively.

CERC	Year Ended December 31,
	2019			2018			2017
	Location and Amount of Gain (Loss) recognized in Income on Hedging Relationship (1)
	Non-utility cost of revenues, including natural gas
	(in millions)
Total amounts presented in the statements of income in which the effects of hedges are recorded	$	3,503		$	4,364		$	3,785
Gain (loss) on fair value hedging relationships:
Commodity contracts:
Hedged items - Natural gas inventory	(14		)	(13		)	14
Derivatives designated as hedging instruments	14			13			(14		)
Amounts excluded from effectiveness testing recognized in earnings immediately	(213		)	(149		)	(67		)

(1) Income statement impact associated with cash flow hedge activity is related to gains and losses reclassified from Accumulated other comprehensive income into income. Amounts are immaterial for the years ended December 31, 2019, 2018 and 2017, respectively.

CenterPoint Energy

		Year Ended December 31,
	Income Statement Location	2019			2018			2017
		(in millions)
Effects of derivatives not designated as hedging instruments on the income statement:
Commodity contracts	Gains (Losses) in Non-utility revenues	$	214		$	107		$	211
Indexed debt securities derivative	Gain (loss) on indexed debt securities	(292		)	(232		)	49
Interest rate derivatives	Gains in Other Income (Expense)	—			2			—
Total CenterPoint Energy		$	(78	)	$	(123	)	$	260

CERC

		Year Ended December 31,
	Income Statement Location	2019		2018		2017
		(in millions)
Effects of derivatives not designated as hedging instruments on the income statement:
Commodity contracts	Gains (Losses) in Non-utility revenues	$	214	$	107	$	211
Total CERC		$	214	$	107	$	211

(c) Credit Risk Contingent Features (CenterPoint Energy and CERC)

CenterPoint Energy and CERC enter into financial derivative contracts containing material adverse change provisions. These provisions could require CenterPoint Energy or CERC to post additional collateral if the S&P or Moody’s credit ratings of CenterPoint Energy, Inc. or its subsidiaries, including CERC Corp., are downgraded.  

	December 31, 2019				December 31, 2018
	CenterPoint Energy		CERC		CenterPoint Energy		CERC
	(in millions)
Aggregate fair value of derivatives containing material adverse change provisions in a net liability position	$	1	$	1	$	1	$	1
Fair value of collateral already posted	—		—		—		—
Additional collateral required to be posted if credit risk contingent features triggered	1		1		—		—

(d) Credit Quality of Counterparties (CenterPoint Energy and CERC)

In addition to the risk associated with price movements, credit risk is also inherent in CenterPoint Energy’s and CERC’s non-trading derivative activities. Credit risk relates to the risk of loss resulting from non-performance of contractual obligations by a counterparty. The following tables show the composition of counterparties to the non-trading derivative assets:

CenterPoint Energy

	December 31, 2019				December 31, 2018
	Investment Grade (1)		Total (3)		Investment Grade (1)		Total (3)
	(in millions)
Energy marketers	$	4	$	16	$	11	$	24
End users (2)	27		178		30		114
Total CenterPoint Energy	$	31	$	194	$	41	$	138

CERC

	December 31, 2019				December 31, 2018
	Investment Grade (1)		Total (3)		Investment Grade (1)		Total (3)
	(in millions)
Energy marketers	$	4	$	16	$	11	$	24
End users (2)	27		178		30		114
Total CERC	$	31	$	194	$	41	$	138

(1) “Investment grade” is primarily determined using publicly available credit ratings and considers credit support (including parent company guarantees) and collateral (including cash and standby letters of credit). For unrated counterparties, CERC determines a synthetic credit rating by performing financial statement analysis and consider contractual rights and restrictions and collateral.

(2) End users are comprised primarily of customers who have contracted to fix the price of a portion of their physical gas requirements for future periods.

(3)

The amounts reflected in the table above were not impacted by collateral netting.

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Revenue Recognition

12 Months Ended

Dec. 31, 2019

Revenue from Contract with Customer [Abstract]

Revenue Recognition [Text Block]

Revenue Recognition

The Registrants adopted ASC 606, Revenue from Contracts with Customers, and all related amendments on January 1, 2018 using the modified retrospective method for those contracts that were not completed as of the date of adoption. Application of the new revenue standard did not result in a cumulative effect adjustment to the opening balance of retained earnings. The comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods. The adoption of the new standard did not have a material impact on the Registrants’ financial position, results of operations or cash flows.

In accordance with ASC 606, revenue is recognized when a customer obtains control of promised goods or services. The amount of revenue recognized reflects the consideration to which the Registrants expect to be entitled to receive in exchange for these goods or services.

The following tables disaggregate revenues by reportable segment and major source:

CenterPoint Energy

	Year Ended December 31, 2019
	Houston Electric T&D (1)			Indiana Electric Integrated (1) (4)		Natural Gas Distribution (1) (4)			Energy  Services (2)			Infrastructure Services (2) (4)			Corporate and Other (2) (4)		Total
	(in millions)
Revenue from contracts	$	2,984		$	523	$	3,680		$	479		$	1,190		$	295	$	9,151
Derivatives income	6			—		2			3,303			—			—		3,311
Other (3)	6			—		1			—			—			5		12
Eliminations	—			—		(40		)	(129		)	(4		)	—		(173		)
Total revenues	$	2,996		$	523	$	3,643		$	3,653		$	1,186		$	300	$	12,301
	Year Ended December 31, 2018
	Houston Electric T&D (1)			Indiana Electric Integrated (1)		Natural Gas Distribution (1)			Energy  Services (2)			Infrastructure Services (2)			Corporate and Other (2)		Total
	(in millions)
Revenue from contracts	$	3,235		$	—	$	3,011		$	493		$	—		$	6	$	6,745
Derivatives income	(2		)	—		(2		)	4,028			—			—		4,024
Other (3)	(1		)	—		(42		)	—			—			9		(34		)
Eliminations	—			—		(36		)	(110		)	—			—		(146		)
Total revenues	$	3,232		$	—	$	2,931		$	4,411		$	—		$	15	$	10,589
	Year Ended December 31, 2017
	Houston Electric T&D (1)			Indiana Electric Integrated (1)		Natural Gas Distribution (1)			Energy Services (2)			Infrastructure Services (2)			Corporate and Other (2)		Total
	(in millions)
Revenue from contracts	$	3,001		$	—	$	2,638		$	480		$	—		$	5	$	6,124
Derivatives income	(1		)	—		—			3,569			—			—		3,568
Other (3)	(3		)	—		1			—			—			9		7
Eliminations	—			—		(33		)	(52		)	—			—		(85		)
Total revenues	$	2,997		$	—	$	2,606		$	3,997		$	—		$	14	$	9,614

(1) Reflected in Utility revenues in the Statements of Consolidated Income.

(2) Reflected in Non-utility revenues in the Statements of Consolidated Income.

(3) Primarily consists of income from ARPs and leases. ARPs are contracts between the utility and its regulators, not between the utility and a customer. The Registrants recognize ARP revenue as other revenues when the regulator-specified conditions for recognition have been met. Upon recovery of ARP revenue through incorporation in rates charged for utility service to customers, ARP revenue is reversed and recorded as revenue from contracts with customers. The recognition of ARP revenues and the reversal of ARP revenues upon recovery through rates charged for utility service may not occur in the same period.

(4) Reflects revenues from Vectren subsidiaries for the period from February 1, 2019 to December 31, 2019.

Houston Electric

	Year Ended December 31,
	2019		2018			2017
	(in millions)
Revenue from contracts	$	2,984	$	3,235		$	3,001
Other (1)	6		(1		)	(3		)
Total revenues	$	2,990	$	3,234		$	2,998

(1) Primarily consists of income from ARPs and leases. ARPs are contracts between the utility and its regulators, not between the utility and a customer. The Registrants recognize ARP revenue as other revenues when the regulator-specified conditions for recognition have been met. Upon recovery of ARP revenue through incorporation in rates charged for utility service to customers, ARP revenue is reversed and recorded as revenue from contracts with customers. The recognition of ARP revenues and the reversal of ARP revenues upon recovery through rates charged for utility service may not occur in the same period.

CERC

	Year Ended December 31, 2019
	Natural Gas Distribution (1)			Energy  Services (2)			Corporate  and Other (2)		Total
	(in millions)
Revenue from contracts	$	2,945		$	480		$	5	$	3,430
Derivatives income	2			3,302			—		3,304
Other (3)	4			—			—		4
Eliminations	(40		)	(128		)	—		(168		)
Total revenues	$	2,911		$	3,654		$	5	$	6,570
	Year Ended December 31, 2018
	Natural Gas Distribution (1)			Energy  Services (2)			Corporate and Other (2)		Total
	(in millions)
Revenue from contracts	$	3,011		$	493		$	1	$	3,505
Derivatives income	(2		)	4,028			—		4,026
Other (3)	(42		)	—			—		(42		)
Eliminations	(36		)	(110		)	—		(146		)
Total revenues	$	2,931		$	4,411		$	1	$	7,343
	Year Ended December 31, 2017
	Natural Gas Distribution (1)			Energy  Services (2)			Corporate and Other (2)		Total
	(in millions)
Revenue from contracts	$	2,638		$	480		$	—	$	3,118
Derivatives income	—			3,569			—		3,569
Other (3)	1			—			—		1
Eliminations	(33		)	(52		)	—		(85		)
Total revenues	$	2,606		$	3,997		$	—	$	6,603

(1) Reflected in Utility revenues in the Statements of Consolidated Income.

(2) Reflected in Non-utility revenues in the Statements of Consolidated Income.

(3) Primarily consists of income from ARPs and leases. ARPs are contracts between the utility and its regulators, not between the utility and a customer. The Registrants recognize ARP revenue as other revenues when the regulator-specified conditions for recognition have been met. Upon recovery of ARP revenue through incorporation in rates charged for utility service to customers, ARP revenue is reversed and recorded as revenue from contracts with customers. The recognition of ARP revenues and the reversal of ARP revenues upon recovery through rates charged for utility service may not occur in the same period.

Revenues from Contracts with Customers

Houston Electric T&D (CenterPoint Energy and Houston Electric). Houston Electric distributes electricity to customers over time and customers consume the electricity when delivered. Revenue, consisting of both volumetric and fixed tariff rates set by the PUCT, is recognized as electricity is delivered and represents amounts both billed and unbilled. Discretionary services

requested by customers are provided at a point in time with control transferring upon the completion of the service. Revenue for discretionary services is recognized upon completion of service based on the tariff rates set by the PUCT. Payments for electricity distribution and discretionary services are aggregated and received on a monthly basis. Houston Electric performs transmission services over time as a stand-ready obligation to provide a reliable network of transmission systems. Revenue is recognized upon time elapsed, and the monthly tariff rate set by the PUCT. Payments are received on a monthly basis.

Indiana Electric Integrated (CenterPoint Energy). Indiana Electric generates, distributes and transmits electricity to customers over time, and customers consume the electricity when delivered. Revenue, consisting of both volumetric and fixed tariff rates set by state regulators, is recognized as electricity is delivered and represents amounts both billed and unbilled. Customers are billed monthly and payment terms, set by the regulator, require payment within a month of billing.

Natural Gas Distribution (CenterPoint Energy and CERC). CERC distributes and transports natural gas to customers over time, and customers consume the natural gas when delivered. Revenue, consisting of both volumetric and fixed tariff rates set by the state governing agency for that service area, is recognized as natural gas is delivered and represents amounts both billed and unbilled. Discretionary services requested by the customer are satisfied at a point in time and revenue is recognized upon completion of service and the tariff rates set by the applicable state regulator. Payments of natural gas distribution, transportation and discretionary services are aggregated and received on a monthly basis.

Energy Services (CenterPoint Energy and CERC). The majority of CES natural gas sales contracts are considered a derivative, as the contracts typically have a stated minimum or contractual volume of delivery.

For contracts in which CES delivers the full requirement of the natural gas needed by the customer and a volume is not stated, a contract as defined under ASC 606 is created upon the customer’s exercise of its option to take natural gas. CES supplies natural gas to retail customers over time as customers consume the natural gas when delivered. For wholesale customers, CES supplies natural gas at a point in time because the wholesale customer is presumed to have storage capabilities. Control is transferred to both types of customers upon delivery of natural gas. Revenue is recognized on a monthly basis based on the estimated volume of natural gas delivered and the price agreed upon with the customer. Payments are received on a monthly basis.

AMAs are natural gas sales contracts under which CES also assumes management of a customer’s physical storage and/or transportation capacity. AMAs have two distinct performance obligations, which consist of natural gas sales and natural gas delivery because delivery could occur separate from the sale of natural gas (e.g., from storage to customer premises). Most AMAs’ natural gas sales performance obligations are accounted for as embedded derivatives. The transaction price is allocated between the sale of natural gas and the delivery based on the stand-alone selling price as stated in the contract. CES performs natural gas delivery over time as customers take delivery of the natural gas and recognizes revenue on an aggregated monthly basis based on the volume of natural gas delivered and the fees stated within the contract. Payments are received on a monthly basis.

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. The transaction is expected to close in the second quarter of 2020. For further information, see Notes 6 and 23.

Infrastructure Services (CenterPoint Energy). Infrastructure Services provides underground pipeline construction and repair services. The contracts are generally less than one year in duration and consist of fixed price, unit, and time and material customer contracts. Under unit or time and material contracts, Infrastructure Services performs construction and repair services under specific work-orders at prices established by master service agreements. The performance obligation is defined at the work-order level. These services are billed to customers monthly or more frequently for work completed based on units completed or the costs of time and material incurred and generally require payment within 30 days of billing. Infrastructure Services has the right to consideration from customers in an amount that corresponds directly with the performance obligation satisfied, and therefore recognizes revenue at a point in time in the amount to which it has the right to invoice, which results in accrued unbilled revenues at the end of each accounting period.

Under fixed price contracts, Infrastructure Services performs larger scale construction and repair services. Each contract is typically accounted for as a single performance obligation. Services performed under fixed price contracts are typically billed per the terms of the contract, which can range from completion of specific milestones to scheduled billing intervals. Billings occur monthly or more frequently for work completed and generally require payment within 30 days of billing. Revenue for fixed price contracts is recognized over time as control is transferred using the input method, considering costs incurred relative to total expected cost. Total expected cost is therefore a significant judgment affecting the amount and timing of revenue recognition. Infrastructure Services’ revenues are not subject to significant returns, refunds or warranty obligations.

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 is expected to close in the second quarter of 2020. For further information, see Notes 6 and 23.

Contract Balances. When the timing of delivery of service is different from the timing of the payments made by customers and when the right to consideration is conditioned on something other than the passage of time, the Registrants recognize either a contract asset (performance precedes billing) or a contract liability (customer payment precedes performance). Those customers that prepay are represented by contract liabilities until the performance obligations are satisfied. The Registrants’ contract assets are included in Accrued unbilled revenues in their Consolidated Balance Sheets. On an aggregate basis as of December 31, 2019, the Registrants’ contract assets primarily relate to contracts in the Infrastructure Services segment where revenue is recognized using the input method. The Registrants’ contract liabilities are included in Accounts payable and Other current liabilities in their Consolidated Balance Sheets. On an aggregate basis as of December 31, 2019, the Registrants’ contract liabilities primarily relate to ESG contracts where revenue is recognized using the input method.

The opening and closing balances of accounts receivable, other accrued unbilled revenue, contract assets and contract liabilities from contracts with customers for the year ended December 31, 2019 are as follows:

CenterPoint Energy

	Accounts Receivable		Other Accrued Unbilled Revenues		Contract Assets		Contract Liabilities
	(in millions)
Opening balance as of December 31, 2018 (1)	$	516	$	373	$	—	$	3
Closing balance as of December 31, 2019	800		579		61		34
Increase	$	284	$	206	$	61	$	31

(1) Opening balances related to Vectren are as of February 1, 2019, and are thus excluded from the opening balance as of December 31, 2018.

The amount of revenue recognized in the year ended December 31, 2019 that was included in the opening contract liability was $47 million. The difference between the opening and closing balances of the contract liabilities primarily results from the timing difference between CenterPoint Energy’s performance and the customer’s payment, plus the addition of obligations acquired in the Merger.

Houston Electric

	Accounts Receivable			Other Accrued Unbilled Revenues		Contract Liabilities
	(in millions)
Opening balance as of December 31, 2018	$	234		$	110	$	3
Closing balance as of December 31, 2019	210			117		3
Increase (decrease)	$	(24	)	$	7	$	—

The amount of revenue recognized in the year ended December 31, 2019 that was included in the opening contract liability was $3 million. The difference between the opening and closing balances of the contract liabilities primarily results from the timing difference between Houston Electric’s performance and the customer’s payment.

CERC

	Accounts Receivable		Other Accrued Unbilled Revenues
	(in millions)
Opening balance as of December 31, 2018	$	282	$	263
Closing balance as of December 31, 2019	282		250
Increase (decrease)	$	—	$	(13	)

CERC does not have any opening or closing contract asset or contract liability balances.

Remaining Performance Obligations (CenterPoint Energy). The table below discloses (1) the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) as of the end of the reporting period for contracts and (2) when CenterPoint Energy expects to recognize this revenue. Such contracts include fixed price contracts and energy performance and sustainable infrastructure services contracts of ESG, which are included in Corporate and Other.

	Rolling 12 Months		Thereafter		Total
	(in millions)
Revenue expected to be recognized on contracts in place as of December 31, 2019:
Infrastructure Services	$	254	$	—	$	254
Corporate and Other	84		752		836
	$	338	$	752	$	1,090

Practical Expedients and Exemption. Sales taxes and other similar taxes collected from customers are excluded from the transaction price. For contracts for which revenue from the satisfaction of the performance obligations is recognized in the amount invoiced, the practical expedient was elected and revenue expected to be recognized on these contracts has not been disclosed.

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Background

12 Months Ended

Dec. 31, 2019

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Background [Text Block]

Background

General. This combined Form 10-K is filed separately by three registrants: CenterPoint Energy, Inc., CenterPoint Energy Houston Electric, LLC and CenterPoint Energy Resources Corp. Information contained herein relating to any individual registrant is filed by such registrant solely on its own behalf. Each registrant makes no representation as to information relating exclusively to the other Registrants or the subsidiaries of CenterPoint Energy other than itself or its subsidiaries.

Except as discussed in Note 14 to the Registrants’ Consolidated Financial Statements, no registrant has an obligation in respect of any other Registrant’s debt securities, and holders of such debt securities should not consider the financial resources or results of operations of any Registrant other than the obligor in making a decision with respect to such securities.

Included in this combined Form 10-K are the Financial Statements of CenterPoint Energy, Houston Electric and CERC, which are referred to collectively as the Registrants. The Combined Notes to the Consolidated Financial Statements apply to all Registrants and specific references to Houston Electric and CERC herein also pertain to CenterPoint Energy, unless otherwise indicated.

Background. CenterPoint Energy, Inc. is a public utility holding company and owns interests in Enable as described below. On the Merger Date, pursuant to the Merger Agreement, CenterPoint Energy consummated the previously announced Merger and acquired Vectren for approximately $6 billion in cash. On the Merger Date, Vectren became a wholly-owned subsidiary of CenterPoint Energy.

As of December 31, 2019, CenterPoint Energy’s operating subsidiaries were as follows:

• Houston Electric owns and operates electric transmission and distribution facilities in the Texas Gulf Coast area that includes the city of Houston; and

• CERC Corp. (i) owns and operates natural gas distribution systems in six states and (ii) obtains and offers competitive variable and fixed-price physical natural gas supplies and services primarily to commercial and industrial customers and electric and natural gas utilities in over 30 states through its wholly-owned subsidiary, CES.

• Vectren holds three public utilities through its wholly-owned subsidiary, VUHI, a public utility holding company:

• Indiana Gas provides energy delivery services to natural gas customers located in central and southern Indiana;

• SIGECO provides energy delivery services to electric and natural gas customers located near Evansville in southwestern Indiana and owns and operates electric generation assets to serve its electric customers and optimizes those assets in the wholesale power market; and

• VEDO provides energy delivery services to natural gas customers located near Dayton in west-central Ohio.

• Vectren performs non-utility activities through:

• Infrastructure Services, which provides underground pipeline construction and repair services through wholly-owned subsidiaries Miller Pipeline, LLC and Minnesota Limited, LLC and serves natural gas utilities across the United States, focusing on recurring integrity, station and maintenance work and opportunities for large transmission pipeline construction projects; and

• ESG, which provides energy performance contracting and sustainable infrastructure services, such as renewables, distributed generation and combined heat and power projects.

For a description of CenterPoint Energy’s and CERC’s reportable segments, see Note 19. Houston Electric consists of a single reportable segment, Houston Electric T&D.

As of December 31, 2019, CenterPoint Energy, indirectly through CNP Midstream, owned approximately 53.7% of the common units representing limited partner interests in Enable, 50% of the management rights and 40% of the incentive distribution rights in Enable GP and also directly owned an aggregate of 14,520,000 Enable Series A Preferred Units. Enable owns, operates and develops natural gas and crude oil infrastructure assets.

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 is expected to close in the second quarter of 2020. For further information, see Notes 6 and 23.

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. The transaction is expected to close in the second quarter of 2020. For further information, see Notes 6 and 23.

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Leases (Notes)

12 Months Ended

Dec. 31, 2019

Leases [Abstract]

Leases [Text Block]

Leases

The Registrants adopted ASC 842, Leases, and all related amendments on January 1, 2019 using the modified retrospective transition method and elected not to recast comparative periods in the year of adoption as permitted by the standard. There was no adjustment to retained earnings as a result of transition. As a result, disclosures for periods prior to adoption will be presented in accordance with accounting standards in effect for those periods. The Registrants also elected the package of practical expedients permitted under the transition guidance within the new standard, which among other things, allowed them to carry forward the historical lease classification. Additionally, the Registrants elected the practical expedient related to land easements, which allows the carry forward of the accounting treatment for land easements on existing agreements. The total ROU assets obtained in exchange for new operating lease liabilities upon adoption were $30 million, $1 million and $27 million for CenterPoint Energy, Houston Electric and CERC, respectively. The Merger was completed on February 1, 2019, and as such the amounts recorded upon adoption are exclusive of Vectren’s leases.

An arrangement is determined to be a lease at inception based on whether the Registrant has the right to control the use of an identified asset. ROU assets represent the Registrants’ right to use the underlying asset for the lease term and lease liabilities represent the Registrants’ obligation to make lease payments arising from the lease. ROU assets and liabilities are recognized at the lease commencement date based on the present value of lease payments over the lease term, including payments at commencement that depend on an index or rate. Most leases in which the Registrants are the lessee do not have a readily determinable implicit rate, so an incremental borrowing rate, based on the information available at the lease commencement date, is utilized to determine the present value of lease payments. When a secured borrowing rate is not readily available, unsecured borrowing rates are adjusted for the effects of collateral to determine the incremental borrowing rate. Each Registrant uses the implicit rate for agreements in which it is a lessor. Lease expense and lease income are recognized on a straight-line basis over the lease term for operating leases.

The Registrants have lease agreements with lease and non-lease components and have elected the practical expedient to combine lease and non-lease components for certain classes of leases, such as office buildings. For classes of leases in which lease and non-lease components are not combined, consideration is allocated between components based on the stand-alone prices. Sublease income is not significant to the Registrants.

The Registrants’ lease agreements do not contain any material residual value guarantees, material restrictions or material covenants. There are no material lease transactions with related parties. Agreements in which the Registrants are lessors do not include provisions for the lessee to purchase the assets. Because risk is minimal, the Registrants do not take any significant actions to manage risk associated with the residual value of their leased assets.

The Registrants’ lease agreements are primarily equipment and real property leases, including land and office facility leases. The Registrants’ lease terms may include options to extend or terminate a lease when it is reasonably certain that those options will be exercised. Operating lease payments exclude approximately $16 million of legally-binding undiscounted minimum lease payments for leases signed but not yet commenced. The Registrants have elected an accounting policy that exempts leases with terms of one year or less from the recognition requirements of ASC 842.

The components of lease cost, included in Operation and maintenance expense on the Registrants’ respective Statements of Consolidated Income, are as follows:

	Year Ended December 31, 2019
	CenterPoint Energy		Houston Electric		CERC
	(in millions)
Operating lease cost	$	25	$	—	$	5
Short-term lease cost	75		23		—
Variable lease cost	1		—		1
Total lease cost	$	101	$	23	$	6

The components of lease income were as follows:

	Year Ended December 31, 2019
	CenterPoint Energy		Houston Electric		CERC
	(in millions)
Operating lease income	$	4	$	2	$	1
Variable lease income	2		—		—
Total lease income	$	6	$	2	$	1

Supplemental balance sheet information related to leases was as follows:

	December 31, 2019
	CenterPoint Energy			Houston Electric			CERC
	(in millions, except lease term and discount rate)
Assets:
Operating ROU assets (1)	$	63		$	1		$	24
Total leased assets	$	63		$	1		$	24
Liabilities:
Current operating lease liability (2)	$	21		$	—		$	4
Non-current operating lease liability (3)	42			1			20
Total leased liabilities	$	63		$	1		$	24
Weighted-average remaining lease term (in years) - operating leases	5.1			5.2			7.7
Weighted-average discount rate - operating leases	3.42		%	3.52		%	3.67		%

(1) Reported within Other assets in the Registrants’ respective Consolidated Balance Sheets.

(2) Reported within Current other liabilities in the Registrants’ respective Consolidated Balance Sheets.

(3) Reported within Other liabilities in the Registrants’ respective Consolidated Balance Sheets.

As of December 31, 2019, maturities of operating lease liabilities were as follows:

	CenterPoint Energy		Houston  Electric		CERC
	(in millions)
2020	$	22	$	1	$	6
2021	16		—		4
2022	9		—		4
2023	7		—		3
2024	3		—		2
2025 and beyond	12		—		9
Total lease payments	69		1		28
Less: Interest	6		—		4
Present value of lease liabilities	$	63	$	1	$	24

The following table sets forth information concerning the Registrants’ obligations under non-cancelable long-term operating leases as of December 31, 2018:    

	CenterPoint Energy		Houston  Electric		CERC
	(in millions)
2019	$	6	$	1	$	5
2020	6		—		5
2021	5		—		4
2022	4		—		4
2023	3		—		3
2024 and beyond	12		—		11
Total (1)	$	36	$	1	$	32

(1) The Merger was completed on February 1, 2019. As such, these amounts are exclusive of Vectren’s leases.

As of December 31, 2019, maturities of undiscounted operating lease payments to be received are as follows:

	CenterPoint Energy		Houston  Electric		CERC
	(in millions)
2020	$	3	$	1	$	1
2021	2		—		—
2022	2		—		—
2023	2		—		—
2024	2		—		—
2025 and beyond	10		—		—
Total lease payments to be received	$	21	$	1	$	1

Other information related to leases is as follows. See Note 20 for information on ROU assets obtained in exchange for operating lease liabilities:

	Year Ended December 31, 2019
	CenterPoint Energy		Houston Electric		CERC
	(in millions)
Operating cash flows from operating leases included in the measurement of lease liabilities	$	25	$	1	$	6

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Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2019

Accounting Policies [Abstract]

Public Utilities General Disclosures [Table Text Block]

The Registrants capitalize interest and AFUDC as a component of projects under construction and amortize it over the assets’ estimated useful lives once the assets are placed in service. AFUDC represents the composite interest cost of borrowed funds and a reasonable return on the equity funds used for construction for subsidiaries that apply the guidance for accounting for regulated operations. Although AFUDC increases both utility plant and earnings, it is realized in cash when the assets are included in rates.

	Year Ended December 31,
	2019						2018						2017
	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC
	(in millions)
Interest and AFUDC debt (1)	$	36	$	8	$	3	$	8	$	6	$	2	$	9	$	6	$	2
AFUDC equity (2)	22		15		3		12		10		2		11		10		1

(1) Included in Interest and other finance charges on the Registrants’ respective Statements of Consolidated Income.

(2)

Included in Other Income (Expense) on the Registrants’ respective Statements of Consolidated Income.

Provision for doubtful accounts [Table Text Block]

The table below summarizes the Registrants’ provision for doubtful accounts for 2019, 2018 and 2017:

	Year Ended December 31,
	2019						2018						2017
	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC
	(in millions)
Provision for doubtful accounts	$	16	$	—	$	12	$	16	$	—	$	16	$	14	$	1	$	13

Schedule of New Accounting Pronouncements and Changes in Accounting Principles [Table Text Block]

The following table provides an overview of certain recently adopted or issued accounting pronouncements applicable to all the Registrants, unless otherwise noted.

Recently Adopted Accounting Standards
ASU Number and Name	Description	Date of Adoption	Financial Statement Impact upon Adoption
ASU 2016-02- Leases (Topic 842) and related amendments	ASU 2016-02 provides a comprehensive new lease model that requires lessees to recognize assets and liabilities for most leases and would change certain aspects of lessor accounting. Transition method: modified retrospective	January 1, 2019	The Registrants adopted the standard and recognized a right-of-use asset and lease liability on their statement of financial position with no material impact on their results of operations and cash flows. See Note 22 for more information.

Issued, Not Yet Effective Accounting Standards
ASU Number and Name	Description	Effective Date	Financial Statement Impact upon Adoption
ASU 2016-13- Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments	This standard, including standards amending this standard, requires a new model called CECL to estimate credit losses for (1) financial assets subject to credit losses and measured at amortized cost and (2) certain off-balance sheet credit exposures. Upon initial recognition of the exposure, the CECL model requires an entity to estimate the credit losses expected over the life of an exposure based on historical information, current information and reasonable and supportable forecasts, including estimates of prepayments. Transition method: modified retrospective	January 1, 2020 Early adoption is permitted	The adoption of this standard will result in an immaterial adjustment to the carrying value of the Registrants’ accounts receivable, net. The adoption of this standard will not have a material impact on the Registrants’ financial position, results of operations or cash flows.
ASU 2018-13- Fair Value Measurement (Topic 820): Disclosure Framework-Changes to the Disclosure Requirements for Fair Value Measurement	This standard eliminates, modifies and adds certain disclosure requirements for fair value measurements. Transition method: prospective for additions and one modification and retrospective for all other amendments	Adoption of eliminations and modifications as of September 30, 2018; Additions will be adopted January 1, 2020	The adoption of this standard did not impact the Registrants’ financial position, results of operations or cash flows. Note 10 reflects the disclosures modified upon adoption.
ASU 2018-15-Intangibles-Goodwill and Other- Internal-Use Software (Subtopic 350-40): Customer's Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract	This standard aligns accounting for implementation costs incurred in a cloud computing arrangement that is accounted for as a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. The update also prescribes the balance sheet, income statement and cash flow classification of the capitalized implementation costs and related amortization expense and requires additional quantitative and qualitative disclosures. Transition method: retrospective or prospective	January 1, 2020 Early adoption is permitted	The adoption of this standard will require the Registrants to capitalize certain costs to implement cloud computing arrangements that are accounted for as service contracts within Prepaid expenses and other current assets on the Registrants’ consolidated balance sheets and record the amortization of such assets within Operation and maintenance expenses on the Registrants’ statements of consolidated income. The adoption of this standard will not have a material impact on the Registrants’ financial position, results of operations, cash flows or disclosures.

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Subsequent Events (Tables)

12 Months Ended

Dec. 31, 2019

Subsequent Events [Abstract]

Schedule of Subsequent Events [Table Text Block]

CenterPoint Energy Dividend Declarations (CenterPoint Energy)

Equity Instrument	Declaration Date	Record Date	Payment Date	Per Share
Common Stock	February 3, 2020	February 20, 2020	March 12, 2020	$	0.2900
Series A Preferred Stock	February 3, 2020	February 14, 2020	March 2, 2020	30.6250
Series B Preferred Stock	February 3, 2020	February 14, 2020	March 2, 2020	17.5000

Enable Distributions Declarations (CenterPoint Energy)

Equity Instrument	Declaration Date	Record Date	Payment Date	Per Unit Distribution		Expected Cash Distribution
						(in millions)
Enable common units	February 7, 2020	February 18, 2020	February 25, 2020	$	0.3305	$	77
Enable Series A Preferred Units	February 7, 2020	February 7, 2020	February 14, 2020	0.6250		9

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Reportable Segments (Tables)

12 Months Ended

Dec. 31, 2019

Segment Reporting [Abstract]

Financial Data for Business Segments [Table Text Block]

Financial data for reportable segments and products and services are as follows:

CenterPoint Energy

	Revenues from External Customers			Net Intersegment Revenues			Depreciation and Amortization		Operating Income (Loss)			Total Assets				Expenditures for Long-Lived Assets
	(in millions)
As of and for the year ended December 31, 2019:
Houston Electric T&D	$	2,996	(1)	$	—		$	648	$	624		$	11,264			$	1,033
Indiana Electric Integrated	523			—			91		90			3,168				183
Natural Gas Distribution	3,643			40			417		408			13,903				1,098
Energy Services	3,653			129			16		32			1,301				12
Infrastructure Services	1,186		(2)	4			50		95			1,077				67
Midstream Investments (3)	—			—			—		—			2,473				—
Corporate and Other	300			—			65		(23		)	4,784			(4)	194
Eliminations	—			(173		)	—		—			(2,531		)		—
Consolidated	$	12,301		$	—		$	1,287	$	1,226		$	35,439			$	2,587
Reconciling items																(81		)
Capital expenditures per Statements of Consolidated Cash Flows																$	2,506
As of and for the year ended December 31, 2018:
Houston Electric T&D	$	3,232	(1)	$	—		$	917	$	623		$	10,509			$	952
Natural Gas Distribution	2,931			36			277		266			6,956				638
Energy Services	4,411			110			16		(47		)	1,558				20
Midstream Investments (3)	—			—			—		—			2,482				—
Corporate and Other	15			—			33		(11		)	6,156			(4)	110
Eliminations	—			(146		)	—		—			(652		)		—
Consolidated	$	10,589		$	—		$	1,243	$	831		$	27,009			$	1,720
Reconciling items																(69		)
Capital expenditures per Statements of Consolidated Cash Flows																$	1,651
As of and for the year ended December 31, 2017:
Houston Electric T&D	$	2,997	(1)	$	—		$	724	$	636		$	10,292			$	924
Natural Gas Distribution	2,606			33			260		348			6,608				523
Energy Services	3,997			52			19		126			1,521				11
Midstream Investments (3)	—			—			—		—			2,472				—
Corporate and Other	14			—			33		26			2,497			(4)	36
Eliminations	—			(85		)	—		—			(654		)		—
Consolidated	$	9,614		$	—		$	1,036	$	1,136		$	22,736			$	1,494
Reconciling items																(68		)
Capital expenditures per Statements of Consolidated Cash Flows																$	1,426

(1) CenterPoint Energy’s Houston Electric T&D’s revenues from major customers are as follows:

	Year Ended December 31,
	2019		2018		2017
	(in millions)
Affiliates of NRG	$	727	$	705	$	713
Affiliates of Vistra Energy Corp.	263		251		229

(2) Includes revenues not eliminated in consolidation for pipeline construction and repair services of $162 million capitalized by CenterPoint Energy’s NGD for the 11 months ended December 31, 2019. See Note 2(b).

(3) CenterPoint Energy’s Midstream Investments’ equity earnings, net are as follows:

	Year Ended December 31,
	2019		2018		2016
	(in millions)
Enable	$	229	$	307	$	265

(4) Total assets included pension and other postemployment-related regulatory assets of $584 million, $665 million and $600 million as of December 31, 2019, 2018 and 2017, respectively. Additionally, total assets as of December 31, 2018 included $3.9 billion of temporary investments included in Cash and cash equivalents on CenterPoint Energy’s Consolidated Balance Sheets.

Houston Electric

Houston Electric consists of a single reportable segment; therefore, a tabular reportable segment presentation has not been

included.

(1) Houston Electric’s revenues from major external customers are as follows:

	Year Ended December 31,
	2019		2018		2017
	(in millions)
Affiliates of NRG	$	727	$	705	$	713
Affiliates of Vistra Energy Corp.	263		251		229

CERC

	Revenues from External Customers		Net Intersegment Revenues			Depreciation and Amortization		Operating Income (Loss)			Total Assets (1)			Expenditures for Long-Lived Assets
	(in millions)
As of and for the year ended December 31, 2019:
Natural Gas Distribution	$	2,911	$	40		$	289	$	316		$	7,497		$	773
Energy Services	3,654		128			16		32			1,301			12
Other Operations	5		—			—		2			149			—
Eliminations	—		(168		)	—		—			(508		)	—
Consolidated	$	6,570	$	—		$	305	$	350		$	8,439		$	785
Reconciling items														(9		)
Capital expenditures per Statements of Consolidated Cash Flows														$	776
As of and for the year ended December 31, 2018:
Natural Gas Distribution	$	2,931	$	36		$	277	$	266		$	6,956		$	638
Energy Services	4,411		110			16		(47		)	1,558			20
Other Operations	1		—			—		3			66			—
Eliminations	—		(146		)	—		—			(366		)	—
Consolidated	$	7,343	$	—		$	293	$	222		$	8,214		$	658
Reconciling items														(25		)
Capital expenditures per Statements of Consolidated Cash Flows														$	633

	Revenues from External Customers		Net Intersegment Revenues			Depreciation and Amortization		Operating Income (Loss)			Total Assets (1)				Expenditures for Long-Lived Assets
	(in millions)
As of and for the year ended December 31, 2017:
Natural Gas Distribution	$	2,606	$	33		$	260	$	348		$	6,608			$	523
Energy Services	3,997		52			19		126			1,521				11
Discontinued operations	—		—			—		—			2,472			(1)	—
Other Operations	—		—			—		(7		)	70				—
Eliminations	—		(85		)	—		—			(559		)		—
Consolidated	$	6,603	$	—		$	279	$	467		$	10,112			$	534
Reconciling items															(21		)
Capital expenditures per Statements of Consolidated Cash Flows															$	513

(1)

On September 4, 2018, CERC completed the Internal Spin. For further information regarding the Internal Spin, see Note 11.

Schedule of Revenue by Major Customers by Reporting Segments [Table Text Block]

CenterPoint Energy’s Houston Electric T&D’s revenues from major customers are as follows:

	Year Ended December 31,
	2019		2018		2017
	(in millions)
Affiliates of NRG	$	727	$	705	$	713
Affiliates of Vistra Energy Corp.	263		251		229

Midstream Investments [Table Text Block]

CenterPoint Energy’s Midstream Investments’ equity earnings, net are as follows:

	Year Ended December 31,
	2019		2018		2016
	(in millions)
Enable	$	229	$	307	$	265

Revenues by Products and Services [Table Text Block]

	Year Ended December 31,
	2019						2018						2017
Revenues by Products and Services:	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC
	(in millions)
Electric delivery	$	3,019	$	2,990	$	—	$	3,232	$	3,234	$	—	$	2,997	$	2,998	$	—
Retail electric sales	486		—		—		—		—		—		—		—		—
Wholesale electric sales	14		—		—		—		—		—		—		—		—
Retail gas sales	4,802		—		4,070		4,161		—		4,161		3,634		—		3,634
Wholesale gas sales	2,312		—		2,313		3,008		—		3,008		2,811		—		2,811
Gas transportation and processing	33		—		33		32		—		32		29		—		29
Infrastructure services	1,186		—		—		—		—		—		—		—		—
Energy products and services	449		—		154		156		—		142		143		—		129
Total	$	12,301	$	2,990	$	6,570	$	10,589	$	3,234	$	7,343	$	9,614	$	2,998	$	6,603

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Short Term Borrowings and Long Term Debt Long-term Debt (Details)			1 Months Ended	12 Months Ended
		Dec. 30, 2019 USD ($)	Jan. 31, 2019 USD ($)	Dec. 31, 2019 USD ($) day		Aug. 12, 2019 USD ($)	May 15, 2019 USD ($)	Feb. 08, 2019 USD ($)	[1]	Jan. 15, 2019 USD ($)	Dec. 31, 2018 USD ($)
Line of Credit Facility [Abstract]
Size of credit facility				$ 5,100,000,000
Annual maturities of long term debt, capital leases, and sinking fund requirements, excluding ZENS obligations [Abstract]
Number of days until commercial paper maturity | day				60
Senior Notes due 2022 [Member]
Long-term debt:
Amount of debt retired		$ 3,000,000
Debt instrument interest rate		3.33%
Senior Notes due 2025 [Member]
Long-term debt:
Amount of debt retired		$ 6,000,000
Debt instrument interest rate		4.53%
Variable rate term loan [Member]
Long-term debt:
Debt instrument interest rate				2.275%
Principal amount of debt issued							$ 1,000,000,000	$ 25,000,000
Annual maturities of long term debt, capital leases, and sinking fund requirements, excluding ZENS obligations [Abstract]
Long-Term				$ 1,000,000,000
Variable term rate loan 2 [Member]
Long-term debt:
Debt instrument interest rate				2.56%
Senior Notes Due 2030 [Member]
Long-term debt:
Debt instrument interest rate				2.95%
Senior Notes Due 2049 [Member]
Long-term debt:
Debt instrument interest rate				3.70%
Commercial paper (4)
Annual maturities of long term debt, capital leases, and sinking fund requirements, excluding ZENS obligations [Abstract]
Long-Term	[2]			$ 1,901,000,000	[3]						$ 0
Pollution control bonds 5.125% due 2028 (5)
Annual maturities of long term debt, capital leases, and sinking fund requirements, excluding ZENS obligations [Abstract]
Long-Term	[4]			68,000,000							68,000,000
Senior Notes due 2022 and 2025 [Member]
Annual maturities of long term debt, capital leases, and sinking fund requirements, excluding ZENS obligations [Abstract]
Make-whole premium		$ 1,000,000
Securitization Bonds [Member]
Annual maturities of long term debt, capital leases, and sinking fund requirements, excluding ZENS obligations [Abstract]
2020				231,000,000
2021				211,000,000
2022				219,000,000
2023				156,000,000
2024				162,000,000
Long term Debt Excluding ZENS [Member]
Annual maturities of long term debt, capital leases, and sinking fund requirements, excluding ZENS obligations [Abstract]
2020	[5]			831,000,000
2021	[5]			2,761,000,000
2022	[5]			3,302,000,000
2023	[5]			713,000,000
2024	[5]			1,184,000,000
Houston Electric [Member]
Line of Credit Facility [Abstract]
Size of credit facility				300,000,000
Annual maturities of long term debt, capital leases, and sinking fund requirements, excluding ZENS obligations [Abstract]
2020	[5]			231,000,000
2021	[5]			613,000,000
2022	[5]			519,000,000
2023	[5]			356,000,000
2024	[5]			162,000,000
Additional first mortgage bonds and general mortgage bonds that could be issued				$ 3,700,000,000
Percentage of property additions				70.00%
Houston Electric [Member] | General Mortgage Bonds Due 2049 [Member]
Long-term debt:
Debt instrument interest rate				4.25%
Principal amount of debt issued										$ 700,000,000
Houston Electric [Member] | First mortgage bonds 9.15% due 2021
Long-term debt:
Debt instrument interest rate				9.15%
Annual maturities of long term debt, capital leases, and sinking fund requirements, excluding ZENS obligations [Abstract]
Secured debt amount with asset liens				$ 102,000,000
Replacement fund requirements to be satisfied in 2018				295,000,000
Sinking fund requirements to be satisfied in 2018				1,600,000
Long-Term				102,000,000							102,000,000
Houston Electric [Member] | General mortgage bonds 1.85% to 6.95% due 2021 to 2048
Annual maturities of long term debt, capital leases, and sinking fund requirements, excluding ZENS obligations [Abstract]
Secured debt amount with asset liens				4,000,000,000.0
Long-Term				3,912,000,000							3,212,000,000
CERC Corp [Member]
Line of Credit Facility [Abstract]
Size of credit facility				900,000,000
Annual maturities of long term debt, capital leases, and sinking fund requirements, excluding ZENS obligations [Abstract]
2020				0
2021				593,000,000
2022				376,000,000
2023				300,000,000
2024				0
CERC Corp [Member] | Commercial paper (4)
Annual maturities of long term debt, capital leases, and sinking fund requirements, excluding ZENS obligations [Abstract]
Long-Term	[2],[6]			377,000,000							210,000,000
Revolving Credit Facility [Member]
Annual maturities of long term debt, capital leases, and sinking fund requirements, excluding ZENS obligations [Abstract]
Long-term Line of Credit				0							0
Revolving Credit Facility [Member] | Houston Electric [Member]
Annual maturities of long term debt, capital leases, and sinking fund requirements, excluding ZENS obligations [Abstract]
Long-term Line of Credit				0							0
Revolving Credit Facility [Member] | CERC Corp [Member]
Annual maturities of long term debt, capital leases, and sinking fund requirements, excluding ZENS obligations [Abstract]
Long-term Line of Credit				$ 0							0
Line of Credit [Member] | Houston Electric [Member]
Line of Credit Facility [Abstract]
Percentage on limitation of debt to total capitalization under covenant (in hundredths)	[7]			65.00%
Ratio of indebtedness to net capital	[8]			0.502
Line of Credit [Member] | CERC Corp [Member]
Line of Credit Facility [Abstract]
Percentage on limitation of debt to total capitalization under covenant (in hundredths)				65.00%
Ratio of indebtedness to net capital	[8]			0.464
Line of Credit [Member] | London Interbank Offered Rate (LIBOR) [Member] | Houston Electric [Member]
Line of Credit Facility [Abstract]
Basis spread on LIBOR	[9]			1.125%
Line of Credit [Member] | London Interbank Offered Rate (LIBOR) [Member] | CERC Corp [Member]
Line of Credit Facility [Abstract]
Basis spread on LIBOR	[9]			1.25%
Letter of Credit [Member]
Annual maturities of long term debt, capital leases, and sinking fund requirements, excluding ZENS obligations [Abstract]
Long-term Line of Credit				$ 7,000,000							11,000,000
Letter of Credit [Member] | Houston Electric [Member]
Annual maturities of long term debt, capital leases, and sinking fund requirements, excluding ZENS obligations [Abstract]
Long-term Line of Credit				0							4,000,000
Letter of Credit [Member] | CERC Corp [Member]
Annual maturities of long term debt, capital leases, and sinking fund requirements, excluding ZENS obligations [Abstract]
Long-term Line of Credit				1,000,000							1,000,000
Commercial paper (4)
Annual maturities of long term debt, capital leases, and sinking fund requirements, excluding ZENS obligations [Abstract]
Long-term Line of Credit				2,278,000,000							210,000,000
Commercial paper (4) | Houston Electric [Member]
Annual maturities of long term debt, capital leases, and sinking fund requirements, excluding ZENS obligations [Abstract]
Long-term Line of Credit				$ 0							$ 0
Debt, Weighted Average Interest Rate				0.00%							0.00%
Commercial paper (4) | CERC Corp [Member]
Annual maturities of long term debt, capital leases, and sinking fund requirements, excluding ZENS obligations [Abstract]
Long-term Line of Credit				$ 377,000,000							$ 210,000,000
Debt, Weighted Average Interest Rate				1.94%							2.93%
Vectren [Member]
Line of Credit Facility [Abstract]
Long-term line of credit			90
Vectren [Member] | Commercial paper (4)
Line of Credit Facility [Abstract]
Weighted average interest rate of commercial paper issued in connection with the Merger	[10],[11]		2.88%
Annual maturities of long term debt, capital leases, and sinking fund requirements, excluding ZENS obligations [Abstract]
Long-term Line of Credit	[10],[11]		$ 1,660,000,000
SIGECO [Member] | Letter of Credit [Member]
Annual maturities of long term debt, capital leases, and sinking fund requirements, excluding ZENS obligations [Abstract]
Long-term Line of Credit				$ 21,000,000
Parent Company [Member]
Line of Credit Facility [Abstract]
Size of credit facility				$ 3,300,000,000
Parent Company [Member] | Senior Notes Due 2030 [Member]
Long-term debt:
Principal amount of debt issued						$ 400,000,000
Parent Company [Member] | Senior Notes Due 2024 [Member]
Long-term debt:
Debt instrument interest rate				2.50%
Principal amount of debt issued						500,000,000
Parent Company [Member] | Senior Notes Due 2049 [Member]
Long-term debt:
Principal amount of debt issued						$ 300,000,000
Parent Company [Member] | Pollution control bonds 5.125% due 2028 (5)
Long-term debt:
Debt instrument interest rate				5.125%
Annual maturities of long term debt, capital leases, and sinking fund requirements, excluding ZENS obligations [Abstract]
Secured debt amount with asset liens				$ 68,000,000							$ 68,000,000
Long-Term				68,000,000
Parent Company [Member] | Revolving Credit Facility [Member]
Annual maturities of long term debt, capital leases, and sinking fund requirements, excluding ZENS obligations [Abstract]
Long-term Line of Credit	[12]			$ 0							0
Parent Company [Member] | Line of Credit [Member]
Line of Credit Facility [Abstract]
Percentage on limitation of debt to total capitalization under covenant (in hundredths)	[7]			65.00%
Ratio of indebtedness to net capital	[8]			0.590
Percentage on limitation of debt to total capitalization under covenant amended (in hundredths)				70.00%
System restoration costs threshold for increase in permitted debt to EBITDA covenant ratio				$ 100,000,000
Consecutive period for system restoration costs to exceed $100 million (in months)				12
Parent Company [Member] | Line of Credit [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line of Credit Facility [Abstract]
Basis spread on LIBOR	[9]			1.50%
Parent Company [Member] | Letter of Credit [Member]
Annual maturities of long term debt, capital leases, and sinking fund requirements, excluding ZENS obligations [Abstract]
Long-term Line of Credit	[12]			$ 6,000,000							6,000,000
Parent Company [Member] | Commercial paper (4)
Annual maturities of long term debt, capital leases, and sinking fund requirements, excluding ZENS obligations [Abstract]
Long-term Line of Credit	[12]			$ 1,633,000,000							$ 0
Debt, Weighted Average Interest Rate	[12]			1.95%							0.00%
VUHI [Member]
Line of Credit Facility [Abstract]
Size of credit facility	[13]			$ 400,000,000
Annual maturities of long term debt, capital leases, and sinking fund requirements, excluding ZENS obligations [Abstract]
Credit facility swing line sublimit				10,000,000
Letters of credit swing line sublimit				20,000,000
VUHI [Member] | Revolving Credit Facility [Member]
Annual maturities of long term debt, capital leases, and sinking fund requirements, excluding ZENS obligations [Abstract]
Long-term Line of Credit				$ 0	[14]						$ 0
VUHI [Member] | Line of Credit [Member]
Line of Credit Facility [Abstract]
Percentage on limitation of debt to total capitalization under covenant (in hundredths)	[13]			65.00%
Ratio of indebtedness to net capital	[8],[13]			0.516
VUHI [Member] | Line of Credit [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line of Credit Facility [Abstract]
Basis spread on LIBOR	[9],[13]			1.125%
VUHI [Member] | Letter of Credit [Member]
Annual maturities of long term debt, capital leases, and sinking fund requirements, excluding ZENS obligations [Abstract]
Long-term Line of Credit				$ 0	[14]						0
VUHI [Member] | Commercial paper (4)
Annual maturities of long term debt, capital leases, and sinking fund requirements, excluding ZENS obligations [Abstract]
Long-term Line of Credit				$ 268,000,000	[14]						$ 0
Debt, Weighted Average Interest Rate				2.08%	[14]						0.00%
VCC [Member]
Line of Credit Facility [Abstract]
Size of credit facility	[15]			$ 200,000,000
Annual maturities of long term debt, capital leases, and sinking fund requirements, excluding ZENS obligations [Abstract]
Credit facility swing line sublimit				40,000,000
Letters of credit swing line sublimit				80,000,000
VCC [Member] | Revolving Credit Facility [Member]
Annual maturities of long term debt, capital leases, and sinking fund requirements, excluding ZENS obligations [Abstract]
Long-term Line of Credit				$ 0	[16]						$ 0
VCC [Member] | Line of Credit [Member]
Line of Credit Facility [Abstract]
Percentage on limitation of debt to total capitalization under covenant (in hundredths)	[15]			65.00%
Ratio of indebtedness to net capital	[8],[15]			0.580
VCC [Member] | Line of Credit [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line of Credit Facility [Abstract]
Basis spread on LIBOR	[9],[15]			1.25%
VCC [Member] | Letter of Credit [Member]
Annual maturities of long term debt, capital leases, and sinking fund requirements, excluding ZENS obligations [Abstract]
Long-term Line of Credit				$ 0	[16]						0
VCC [Member] | Commercial paper (4)
Annual maturities of long term debt, capital leases, and sinking fund requirements, excluding ZENS obligations [Abstract]
Long-term Line of Credit				$ 0	[16]						$ 0
Debt, Weighted Average Interest Rate				0.00%	[16]						0.00%
Maximum [Member] | Houston Electric [Member] | General mortgage bonds 1.85% to 6.95% due 2021 to 2048
Long-term debt:
Debt instrument interest rate				6.95%
Maximum [Member] | Parent Company [Member] | Variable rate term loan [Member]
Long-term debt:
Debt instrument interest rate				2.56%
Maximum [Member] | Vectren [Member] | Letter of Credit [Member]
Annual maturities of long term debt, capital leases, and sinking fund requirements, excluding ZENS obligations [Abstract]
Long-term Line of Credit				$ 50,000,000

[1] Draw down by VCC on its variable rate term loan.

[2] Classified as long-term debt because the termination date of the facility that backstops the commercial paper is more than one year from the date noted.

[3] Commercial paper issued by VUHI has maturities up to 30 days.

[4] $68 million and $68 million of these series of debt were secured by general mortgage bonds of Houston Electric as of December 31, 2019 and 2018, respectively. These general mortgage bonds are not reflected in Houston Electric’s consolidated financial statements because of the contingent nature of the obligations.

[5] These maturities include Securitization Bonds principal repayments on scheduled payment dates.

[6] Issued by CERC Corp.

[7] For CenterPoint Energy and Houston Electric, the financial covenant limit will temporarily increase from 65% to 70% if Houston Electric experiences damage from a natural disaster in its service territory and CenterPoint Energy certifies to the administrative agent that Houston Electric has incurred system restoration costs reasonably likely to exceed $100 million in a consecutive 12-month period, all or part of which Houston Electric intends to seek to recover through securitization financing. Such temporary increase in the financial covenant would be in effect from the date CenterPoint Energy delivers its certification until the earliest to occur of (i) the completion of the securitization financing, (ii) the first anniversary of CenterPoint Energy’s certification or (iii) the revocation of such certification.

[8] As defined in the revolving credit facility agreement, excluding Securitization Bonds.

[9] Based on credit ratings as of December 31, 2019.

[10] Proceeds from these commercial paper issuances were used to fund a portion of the Merger and to pay related fees and expenses and were contributed to Vectren for its payment of its stub period cash dividend, long-term incentive payments and to fund the repayment of indebtedness of Vectren subsidiaries redeemed at the option of the holder as a result of the closing of the Merger.

[11] The commercial paper notes were issued at various times in January 2019 with maturities up to and including 90 days as of the time of issuance, and, prior to their use as described in connection with the closing of the Merger, the net proceeds of such issuances were invested in short-term investments.

[12] CenterPoint Energy’s outstanding commercial paper generally has maturities of 60 days or less.

[13] This credit facility was issued by VUHI, is guaranteed by SIGECO, Indiana Gas and VEDO and includes a $10 million swing line sublimit and a $20 million letter of credit sublimit. This credit facility backstops VUHI’s commercial paper program.

[14] This credit facility was issued by VUHI and is guaranteed by SIGECO, Indiana Gas and VEDO.

[15] This credit facility was issued by VCC, is guaranteed by Vectren and includes a $40 million swing line sublimit and an$80 million letter of credit sublimit.

[16] This credit facility was issued by VCC and is guaranteed by Vectren.

XML

Stock-Based Incentive Compensation Plans and Employee Benefit Plans Multi-employer Plan (Details) - Multiemployer Plans, Pension [Member] $ in Millions	12 Months Ended
	Dec. 31, 2019 USD ($)
Multiemployer Plans [Line Items]
Multiemployer Plan, Contributions by Employer	$ 52
Approximate number of unions the Company contributed to on behalf of employees	215
Multiemployer Plans Average Contributions	$ 1
Multiemployer Plans Largest Contribution	$ 5
Number of multiemployer plans contributed to	72
Defined benefit plan, number of significant plans	8
Defined benefit plan, number of plans in red zone status receiving company contributions	4
Defined benefit plan, number of plans whereby company contributions exceed 5% of plan balance	5
Defined benefit plan, percentage threshold by which plan contributions are considered significant	5.00%
Number of plans in red zone status considered significant by the Company	0
Central Pension Fund [Member]
Multiemployer Plans [Line Items]
Multiemployer Plan, Contributions by Employer	$ 12
Multiemployer Plans, Certified Zone Status [Fixed List]	Green
Multiemployer Plans, Funding Improvement Plan and Rehabilitation Plan [Fixed List]	No
Multiemployer Plans, Surcharge [Fixed List]	No
Indiana Laborers Pension Fund [Member]
Multiemployer Plans [Line Items]
Multiemployer Plan, Contributions by Employer	$ 5
Multiemployer Plans, Certified Zone Status [Fixed List]	Green
Multiemployer Plans, Funding Improvement Plan and Rehabilitation Plan [Fixed List]	No
Multiemployer Plans, Surcharge [Fixed List]	No
Pipeline Industry Benefit Fund [Member]
Multiemployer Plans [Line Items]
Multiemployer Plan, Contributions by Employer	$ 5
Multiemployer Plans, Certified Zone Status [Fixed List]	Green
Multiemployer Plans, Funding Improvement Plan and Rehabilitation Plan [Fixed List]	No
Multiemployer Plans, Surcharge [Fixed List]	No
Laborers District Fund of Ohio [Member]
Multiemployer Plans [Line Items]
Multiemployer Plan, Contributions by Employer	$ 4
Multiemployer Plans, Certified Zone Status [Fixed List]	Green
Multiemployer Plans, Funding Improvement Plan and Rehabilitation Plan [Fixed List]	No
Multiemployer Plans, Surcharge [Fixed List]	No
Ohio Operating Engineers Pension Fund [Member]
Multiemployer Plans [Line Items]
Multiemployer Plan, Contributions by Employer	$ 3
Multiemployer Plans, Certified Zone Status [Fixed List]	Green
Multiemployer Plans, Funding Improvement Plan and Rehabilitation Plan [Fixed List]	No
Multiemployer Plans, Surcharge [Fixed List]	No
Operating Eng. Local 324 Fund [Member]
Multiemployer Plans [Line Items]
Multiemployer Plan, Contributions by Employer	$ 3
Multiemployer Plans, Certified Zone Status [Fixed List]	Red
Multiemployer Plans, Funding Improvement Plan and Rehabilitation Plan [Fixed List]	Implemented
Multiemployer Plans, Surcharge [Fixed List]	No
Minnesota Laborers Pension Fund [Member]
Multiemployer Plans [Line Items]
Multiemployer Plan, Contributions by Employer	$ 3
Multiemployer Plans, Certified Zone Status [Fixed List]	Green
Multiemployer Plans, Funding Improvement Plan and Rehabilitation Plan [Fixed List]	No
Multiemployer Plans, Surcharge [Fixed List]	No
Laborers' Combined Fund of Western Pennsylvania [Member]
Multiemployer Plans [Line Items]
Multiemployer Plan, Contributions by Employer	$ 2
Multiemployer Plans, Certified Zone Status [Fixed List]	Red
Multiemployer Plans, Funding Improvement Plan and Rehabilitation Plan [Fixed List]	Implemented
Multiemployer Plans, Surcharge [Fixed List]	No
Other Pension Funds [Member]
Multiemployer Plans [Line Items]
Multiemployer Plan, Contributions by Employer	$ 15

XML

Derivative Instruments Summary of Derivative Activity (Details) $ in Millions		12 Months Ended
		Dec. 31, 2019 USD ($) Bcf	Dec. 31, 2018 USD ($) Bcf	Dec. 31, 2017 USD ($)
Energy Related Derivative [Member]
Derivative Assets (Liabilities), at Fair Value, Net, by Balance Sheet Classification [Abstract]
Derivative gross volume notional amount (in Bcf) | Bcf		2,226	1,674
Gross Amounts Recognized	[1]	$ 51	$ 12
Gross Amounts Offset in the Consolidated Balance Sheets		63	19
Net Amount Presented in the Consolidated Balance Sheets	[2]	114	31
Derivative Assets Fair Value		292	220
Derivative Liabilities Fair Value		1,144	833
Derivative Asset		47	57
Cumulative Amount of Fair Value Hedging Adjustment Included in the Carrying Amount of Hedged Item		(13)	1
Income Statement Impact of Derivative Activity [Abstract]
Total amounts presented in the statements of income in which the effects of hedges are recorded	[3]	4,029	4,364	$ 3,785
Gain (loss) on derivative instruments not designated as hedging instruments		(78)	(123)	260
Derivative, Credit Risk Related Contingent Features [Abstract]
Aggregate fair value of derivatives containing material adverse change provisions in a net liability position		1	1
Fair value of collateral already posted		0	0
Additional collateral required to be posted if credit risk contingent features triggered		1	0
Credit Risk Derivatives, at Fair Value, Net [Abstract]
Total credit risk of counterparties	[4]	194	138
Energy Marketers [Member]
Credit Risk Derivatives, at Fair Value, Net [Abstract]
Total credit risk of counterparties	[4]	16	24
Retail End Users [Member]
Credit Risk Derivatives, at Fair Value, Net [Abstract]
Total credit risk of counterparties	[4],[5]	178	114
External Credit Rating, Investment Grade [Member]
Credit Risk Derivatives, at Fair Value, Net [Abstract]
Total credit risk of counterparties	[6]	31	41
External Credit Rating, Investment Grade [Member] | Energy Marketers [Member]
Credit Risk Derivatives, at Fair Value, Net [Abstract]
Total credit risk of counterparties	[6]	4	11
External Credit Rating, Investment Grade [Member] | Retail End Users [Member]
Credit Risk Derivatives, at Fair Value, Net [Abstract]
Total credit risk of counterparties	[5],[6]	27	30
Current Assets [Member] | Energy Related Derivative [Member]
Derivative Assets (Liabilities), at Fair Value, Net, by Balance Sheet Classification [Abstract]
Derivative Asset	[2]	136	100
Cumulative Amount of Fair Value Hedging Adjustment Included in the Carrying Amount of Hedged Item		(13)	1
Gross Amounts Recognized	[1]	224	166
Gross Amounts Offset		(88)	(66)
Other Noncurrent Assets [Member] | Energy Related Derivative [Member]
Derivative Assets (Liabilities), at Fair Value, Net, by Balance Sheet Classification [Abstract]
Derivative Asset	[2]	58	38
Gross Amounts Recognized	[1]	68	54
Gross Amounts Offset		(10)	(16)
Current Liabilities [Member] | Energy Related Derivative [Member]
Derivative Assets (Liabilities), at Fair Value, Net, by Balance Sheet Classification [Abstract]
Gross Amounts Recognized	[1]	(187)	(183)
Gross Amounts Offset		136	81
Derivative Liability	[2]	(51)	(102)
Other Noncurrent Liabilities [Member] | Energy Related Derivative [Member]
Derivative Assets (Liabilities), at Fair Value, Net, by Balance Sheet Classification [Abstract]
Gross Amounts Recognized	[1]	(54)	(25)
Gross Amounts Offset		25	20
Derivative Liability	[2]	(29)	(5)
Not Designated as Hedging Instrument [Member] | Current Assets [Member] | Energy Related Derivative [Member]
Derivative Assets (Liabilities), at Fair Value, Net, by Balance Sheet Classification [Abstract]
Derivative Assets Fair Value	[7],[8],[9]	139	103
Derivative Liabilities Fair Value	[7],[8],[9]	3	3
Not Designated as Hedging Instrument [Member] | Other Noncurrent Assets [Member] | Energy Related Derivative [Member]
Derivative Assets (Liabilities), at Fair Value, Net, by Balance Sheet Classification [Abstract]
Derivative Assets Fair Value	[7],[8],[9]	58	38
Derivative Liabilities Fair Value	[7],[8],[9]	0	0
Not Designated as Hedging Instrument [Member] | Current Liabilities [Member] | Energy Related Derivative [Member]
Derivative Assets (Liabilities), at Fair Value, Net, by Balance Sheet Classification [Abstract]
Derivative Assets Fair Value	[7],[8],[9]	73	62
Derivative Liabilities Fair Value	[7],[8],[9]	184	173
Not Designated as Hedging Instrument [Member] | Current Liabilities [Member] | IDS Derivative [Member]
Derivative Assets (Liabilities), at Fair Value, Net, by Balance Sheet Classification [Abstract]
Derivative Assets Fair Value		0	0
Derivative Liabilities Fair Value		893	601
Not Designated as Hedging Instrument [Member] | Other Noncurrent Liabilities [Member] | Interest Rate Contract [Member]
Derivative Assets (Liabilities), at Fair Value, Net, by Balance Sheet Classification [Abstract]
Derivative Assets Fair Value		0	0
Derivative Liabilities Fair Value		10	0
Not Designated as Hedging Instrument [Member] | Other Noncurrent Liabilities [Member] | Energy Related Derivative [Member]
Derivative Assets (Liabilities), at Fair Value, Net, by Balance Sheet Classification [Abstract]
Derivative Assets Fair Value	[7],[8],[9]	10	16
Derivative Liabilities Fair Value	[7],[8],[9]	$ 54	$ 25
Long [Member] | Energy Related Derivative [Member]
Derivative Assets (Liabilities), at Fair Value, Net, by Balance Sheet Classification [Abstract]
Derivative gross volume notional amount (in Bcf) | Bcf		374	140
Houston Electric [Member]
Derivative Assets (Liabilities), at Fair Value, Net, by Balance Sheet Classification [Abstract]
Derivative Assets Fair Value		$ 0	$ 0
Derivative Liabilities Fair Value		$ 0	$ 24
CERC Corp [Member] | Energy Related Derivative [Member]
Derivative Assets (Liabilities), at Fair Value, Net, by Balance Sheet Classification [Abstract]
Derivative gross volume notional amount (in Bcf) | Bcf		2,226	1,674
Gross Amounts Recognized	[1]	$ 73	$ 12
Gross Amounts Offset in the Consolidated Balance Sheets		63	19
Net Amount Presented in the Consolidated Balance Sheets	[2]	136	31
CERC Corp [Member]
Derivative Assets (Liabilities), at Fair Value, Net, by Balance Sheet Classification [Abstract]
Derivative Assets Fair Value		292	220
Derivative Liabilities Fair Value		219	208
Derivative Asset		47	57
Cumulative Amount of Fair Value Hedging Adjustment Included in the Carrying Amount of Hedged Item		(13)	1
Income Statement Impact of Derivative Activity [Abstract]
Total amounts presented in the statements of income in which the effects of hedges are recorded	[3]	3,503	4,364	3,785
Gain (loss) on derivative instruments not designated as hedging instruments		214	107	211
Derivative, Credit Risk Related Contingent Features [Abstract]
Aggregate fair value of derivatives containing material adverse change provisions in a net liability position		1	1
Fair value of collateral already posted		0	0
Additional collateral required to be posted if credit risk contingent features triggered		1	0
Credit Risk Derivatives, at Fair Value, Net [Abstract]
Total credit risk of counterparties	[4]	194	138
CERC Corp [Member] | Energy Marketers [Member]
Credit Risk Derivatives, at Fair Value, Net [Abstract]
Total credit risk of counterparties	[4]	16	24
CERC Corp [Member] | Retail End Users [Member]
Credit Risk Derivatives, at Fair Value, Net [Abstract]
Total credit risk of counterparties	[4],[5]	178	114
CERC Corp [Member] | External Credit Rating, Investment Grade [Member]
Credit Risk Derivatives, at Fair Value, Net [Abstract]
Total credit risk of counterparties	[6]	31	41
CERC Corp [Member] | External Credit Rating, Investment Grade [Member] | Energy Marketers [Member]
Credit Risk Derivatives, at Fair Value, Net [Abstract]
Total credit risk of counterparties	[6]	4	11
CERC Corp [Member] | External Credit Rating, Investment Grade [Member] | Retail End Users [Member]
Credit Risk Derivatives, at Fair Value, Net [Abstract]
Total credit risk of counterparties	[5],[6]	27	30
CERC Corp [Member] | Current Assets [Member] | Energy Related Derivative [Member]
Derivative Assets (Liabilities), at Fair Value, Net, by Balance Sheet Classification [Abstract]
Derivative Asset	[2]	136	100
Cumulative Amount of Fair Value Hedging Adjustment Included in the Carrying Amount of Hedged Item		(13)	1
Gross Amounts Recognized	[1]	224	166
Gross Amounts Offset		(88)	(66)
CERC Corp [Member] | Other Noncurrent Assets [Member] | Energy Related Derivative [Member]
Derivative Assets (Liabilities), at Fair Value, Net, by Balance Sheet Classification [Abstract]
Derivative Asset	[2]	58	38
Gross Amounts Recognized	[1]	68	54
Gross Amounts Offset		(10)	(16)
CERC Corp [Member] | Current Liabilities [Member] | Energy Related Derivative [Member]
Derivative Assets (Liabilities), at Fair Value, Net, by Balance Sheet Classification [Abstract]
Gross Amounts Recognized	[1]	(180)	(183)
Gross Amounts Offset		136	81
Derivative Liability	[2]	(44)	(102)
CERC Corp [Member] | Other Noncurrent Liabilities [Member] | Energy Related Derivative [Member]
Derivative Assets (Liabilities), at Fair Value, Net, by Balance Sheet Classification [Abstract]
Gross Amounts Recognized	[1]	(39)	(25)
Gross Amounts Offset		25	20
Derivative Liability	[2]	(14)	(5)
CERC Corp [Member] | Not Designated as Hedging Instrument [Member] | Current Assets [Member] | Energy Related Derivative [Member]
Derivative Assets (Liabilities), at Fair Value, Net, by Balance Sheet Classification [Abstract]
Derivative Assets Fair Value	[10],[11],[12]	139	103
Derivative Liabilities Fair Value	[10],[11],[12]	3	3
CERC Corp [Member] | Not Designated as Hedging Instrument [Member] | Other Noncurrent Assets [Member] | Energy Related Derivative [Member]
Derivative Assets (Liabilities), at Fair Value, Net, by Balance Sheet Classification [Abstract]
Derivative Assets Fair Value	[10],[11],[12]	58	38
Derivative Liabilities Fair Value	[10],[11],[12]	0	0
CERC Corp [Member] | Not Designated as Hedging Instrument [Member] | Current Liabilities [Member] | Energy Related Derivative [Member]
Derivative Assets (Liabilities), at Fair Value, Net, by Balance Sheet Classification [Abstract]
Derivative Assets Fair Value	[10],[11],[12]	73	62
Derivative Liabilities Fair Value	[10],[11],[12]	177	173
CERC Corp [Member] | Not Designated as Hedging Instrument [Member] | Other Noncurrent Liabilities [Member] | Energy Related Derivative [Member]
Derivative Assets (Liabilities), at Fair Value, Net, by Balance Sheet Classification [Abstract]
Derivative Assets Fair Value	[10],[11],[12]	10	16
Derivative Liabilities Fair Value	[10],[11],[12]	$ 39	$ 25
CERC Corp [Member] | Long [Member] | Energy Related Derivative [Member]
Derivative Assets (Liabilities), at Fair Value, Net, by Balance Sheet Classification [Abstract]
Derivative gross volume notional amount (in Bcf) | Bcf		374	140
Cash Flow Hedging [Member] | Designated as Hedging Instrument [Member] | Current Liabilities [Member] | Interest Rate Contract [Member]
Derivative Assets (Liabilities), at Fair Value, Net, by Balance Sheet Classification [Abstract]
Derivative Assets Fair Value		$ 0	$ 0
Derivative Liabilities Fair Value		0	24
Cash Flow Hedging [Member] | Houston Electric [Member] | Designated as Hedging Instrument [Member] | Current Liabilities [Member] | Interest Rate Contract [Member]
Derivative Assets (Liabilities), at Fair Value, Net, by Balance Sheet Classification [Abstract]
Derivative Assets Fair Value		0	0
Derivative Liabilities Fair Value		0	24
Fair Value Hedging [Member] | Current Assets [Member] | Energy Related Derivative [Member]
Derivative Assets (Liabilities), at Fair Value, Net, by Balance Sheet Classification [Abstract]
Derivative Asset		47	57
Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Current Liabilities [Member] | Energy Related Derivative [Member]
Derivative Assets (Liabilities), at Fair Value, Net, by Balance Sheet Classification [Abstract]
Derivative Assets Fair Value	[7],[8],[9]	12	1
Derivative Liabilities Fair Value	[7],[8],[9]	0	7
Fair Value Hedging [Member] | CERC Corp [Member] | Current Assets [Member] | Energy Related Derivative [Member]
Derivative Assets (Liabilities), at Fair Value, Net, by Balance Sheet Classification [Abstract]
Derivative Asset		47	57
Fair Value Hedging [Member] | CERC Corp [Member] | Designated as Hedging Instrument [Member] | Current Liabilities [Member] | Energy Related Derivative [Member]
Derivative Assets (Liabilities), at Fair Value, Net, by Balance Sheet Classification [Abstract]
Derivative Assets Fair Value	[10],[11],[12]	12	1
Derivative Liabilities Fair Value	[10],[11],[12]	0	7
Gains (Losses) in Revenue [Member] | CERC Corp [Member] | Energy Related Derivative [Member]
Income Statement Impact of Derivative Activity [Abstract]
Gain (loss) on derivative instruments not designated as hedging instruments		214	107	211
Natural Gas Expenses [Member] | Fair Value Hedging [Member] | Energy Related Derivative [Member]
Income Statement Impact of Derivative Activity [Abstract]
Change in unrealized gain (loss) on fair value hedging instruments	[3]	(14)	(13)	14
Amounts excluded from effectiveness testing recognized in earnings immediately	[3]	(213)	(149)	(67)
Natural Gas Expenses [Member] | Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member]
Income Statement Impact of Derivative Activity [Abstract]
Change in unrealized gain (loss) on fair value hedging instruments	[3]	14	13	(14)
Natural Gas Expenses [Member] | Fair Value Hedging [Member] | CERC Corp [Member] | Energy Related Derivative [Member]
Income Statement Impact of Derivative Activity [Abstract]
Change in unrealized gain (loss) on fair value hedging instruments	[13]	(14)	(13)	14
Amounts excluded from effectiveness testing recognized in earnings immediately	[13]	(213)	(149)	(67)
Natural Gas Expenses [Member] | Fair Value Hedging [Member] | CERC Corp [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member]
Income Statement Impact of Derivative Activity [Abstract]
Change in unrealized gain (loss) on fair value hedging instruments	[13]	14	13	(14)
Gains (Losses) in Other Income (Expense) [Member] | Interest Rate Contract [Member]
Income Statement Impact of Derivative Activity [Abstract]
Gain (loss) on derivative instruments not designated as hedging instruments		0	2	0
Gains (Losses) in Other Income (Expense) [Member] | IDS Derivative [Member]
Income Statement Impact of Derivative Activity [Abstract]
Gain (loss) on derivative instruments not designated as hedging instruments		$ (292)	$ (232)	$ 49

[1] Gross amounts recognized include some derivative assets and liabilities that are not subject to master netting arrangements.

[2] The derivative assets and liabilities on the Registrant’s respective Consolidated Balance Sheets exclude accounts receivable or accounts payable that, should they exist, could be used as offsets to these balances in the event of a default.

[3] Income statement impact associated with cash flow hedge activity is related to gains and losses reclassified from Accumulated other comprehensive income into income. Amounts are immaterial for the years ended December 31, 2019, 2018 and 2017, respectively.

[4] The amounts reflected in the table above were not impacted by collateral netting.

[5] End users are comprised primarily of customers who have contracted to fix the price of a portion of their physical gas requirements for future periods.

[6] “Investment grade” is primarily determined using publicly available credit ratings and considers credit support (including parent company guarantees) and collateral (including cash and standby letters of credit). For unrated counterparties, CERC determines a synthetic credit rating by performing financial statement analysis and consider contractual rights and restrictions and collateral.

[7] Derivative Assets and Derivative Liabilities include no material amounts related to physical forward transactions with Enable.

[8] The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling 2,226 Bcf or a net 374 Bcf long position and 1,674 Bcf or a net 140 Bcf long position as of December 31, 2019 and 2018, respectively. Certain natural gas contracts hedge basis risk only and lack a fixed price exposure.

[9] Natural gas contracts are presented on a net basis in CenterPoint Energy’s Consolidated Balance Sheets as they are subject to master netting arrangements. This netting applies to all undisputed amounts due or past due and causes derivative assets (liabilities) to be ultimately presented net in a liability (asset) account within CenterPoint Energy’s Consolidated Balance Sheets. The net of total non-trading natural gas derivative assets and liabilities is detailed in the Offsetting of Natural Gas Derivative Assets and Liabilities table below

[10] Derivative Assets and Derivative Liabilities include no material amounts related to physical forward transactions with Enable.

[11] Natural gas contracts are presented on a net basis in CERC’s Consolidated Balance Sheets as they are subject to master netting arrangements. This netting applies to all undisputed amounts due or past due and causes derivative assets (liabilities) to be ultimately presented net in a liability (asset) account within CERC’s Consolidated Balance Sheets. The net of total non-trading natural gas derivative assets and liabilities is detailed in the Offsetting of Natural Gas Derivative Assets and Liabilities table below.

[12] The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling 2,226 Bcf or a net 374 Bcf long position and 1,674 Bcf or a net 140 Bcf long position as of December 31, 2019 and 2018, respectively. Certain natural gas contracts hedge basis risk only and lack a fixed price exposure.

[13] Income statement impact associated with cash flow hedge activity is related to gains and losses reclassified from Accumulated other comprehensive income into income. Amounts are immaterial for the years ended December 31, 2019, 2018 and 2017, respectively.

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Earnings Per Share (CenterPoint Energy) (Details) - USD ($) $ / shares in Units, $ in Millions		3 Months Ended																12 Months Ended
		Dec. 31, 2019		Sep. 30, 2019		Jun. 30, 2019		Mar. 31, 2019		Dec. 31, 2018		Sep. 30, 2018		Jun. 30, 2018		Mar. 31, 2018		Dec. 31, 2019		Dec. 31, 2018		Dec. 31, 2017
Net income																		$ 791		$ 368		$ 1,792
Numerator:
Income available to common shareholders - basic (1)		$ 128		$ 241		$ 165		$ 140		$ 90		$ 153		$ (75)		$ 165		674	[1]	333	[1]	1,792	[1]
Add back: Series B Preferred Stock dividend																		117		35		0
Income available to common shareholders - diluted (1)	[1]																	$ 674		$ 333		$ 1,792
Denominator:
Weighted average common shares outstanding - basic																		502,050,000		448,829,000		430,964,000
Plus: Incremental shares from assumed conversions:
Weighted average common shares outstanding - diluted																		505,157,000		452,465,000		434,308,000
Basic Earnings Per Common Share		$ 0.25	[2]	$ 0.48	[2]	$ 0.33	[2]	$ 0.28	[2]	$ 0.18	[2]	$ 0.35	[2]	$ (0.17)	[2]	$ 0.38	[2]	$ 1.34		$ 0.74		$ 4.16
Diluted Earnings Per Common Share		$ 0.25	[2]	$ 0.47	[2]	$ 0.33	[2]	$ 0.28	[2]	$ 0.18	[2]	$ 0.35	[2]	$ (0.17)	[2]	$ 0.38	[2]	$ 1.33		$ 0.74		$ 4.13
Reduction in income taxes due to tax reform																		$ 0		$ 0		$ 1,113	[3]
Preferred Stock Dividends, Income Statement Impact																		$ 117		$ 35		$ 0
Restricted Stock [Member]
Plus: Incremental shares from assumed conversions:
Restricted stock (3)	[4]																	3,107,000		3,636,000		3,344,000
Series B Preferred Stock [Member]
Numerator:
Add back: Series B Preferred Stock dividend	[5]																	$ 0		$ 0		$ 0
Plus: Incremental shares from assumed conversions:
Series B Preferred Stock (2)	[5]																	0		0		0
Preferred Stock Dividends, Income Statement Impact																		$ 68		$ 17		$ 0
Amount of antidilutive securities excluded from computation of earnings per share																		34,354,000		8,885,000
Vectren [Member]
Net income																		$ 190

[1] Income available to common shareholders for the year ended December 31, 2019 includes net income from businesses acquired in the Merger of $190 million. See Note 4. Income available to common shareholders for the year ended December 31, 2017 includes a reduction in income tax expense of $1,113 million due to tax reform. See Note 15 for further discussion of the impacts of the TCJA.

[2] Quarterly earnings (loss) per common share are based on the weighted average number of shares outstanding during the quarter, and the sum of the quarters may not equal annual earnings (loss) per common share.

[3] Recognized a $1.1 billion deferred tax benefit from the remeasurement of CenterPoint Energy’s ADFIT liability as a result of the enactment of the TCJA on December 22, 2017, which reduced the U.S. corporate income tax rate from 35% to 21%.

[4] The potentially dilutive impact from restricted stock awards applies the treasury stock method. Under this method, an increase in the average fair market value of Common Stock can result in a greater dilutive impact from these securities.

[5] The potentially dilutive impact from Series B Preferred Stock applies the if-converted method in calculating diluted earnings per common share. Under this method, diluted earnings per common share is adjusted for the more dilutive effect of the Series B Preferred Stock as a result of either its accumulated dividend for the period in the numerator or the assumed-converted common share equivalent in the denominator. The computation of diluted earnings per common share outstanding for the year ended December 31, 2019 and December 31, 2018 excludes Series B Stock Dividends of $68 million and $17 million, respectively, and 34,354,000 and 8,885,000 potentially dilutive shares, respectively, because to include them would be anti-dilutive. However, these shares could be potentially dilutive in the future.

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Supplemental Disclosure of Cash Flow Information (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019		Dec. 31, 2018		Dec. 31, 2017	Dec. 31, 2016
Interest, net of capitalized interest		$ 436		$ 363		$ 378
Income taxes (refunds), net		155		89		15
Accounts payable related to capital expenditures		236		201		144
Capital distribution associated with the Internal Spin		0		0		0
ROU Asset Obtained In Exchange for Operating Lease Liability, Including Transition Impact of ASC 842 Adoption		44	[1]	0		0
Cash and cash equivalents	[2]	241		4,231
Total cash, cash equivalents and restricted cash shown in Statements of Consolidated Cash Flows		271		4,278		296	$ 381
Other, net [Member]
Interest income		22		28		2
Cash and Cash Equivalents [Member]
Temporary investments		3,900
Prepaid Expenses and Other Current Assets [Member]
Restricted cash		30		46
Other Noncurrent Assets [Member]
Restricted cash		0		1
Houston Electric [Member]
Interest, net of capitalized interest		229		200		205
Income taxes (refunds), net		87		154		76
Accounts payable related to capital expenditures		117		124		104
Capital distribution associated with the Internal Spin		0		0		0
ROU Asset Obtained In Exchange for Operating Lease Liability, Including Transition Impact of ASC 842 Adoption		1	[1]	0		0
Cash and cash equivalents	[3]	216		335
Total cash, cash equivalents and restricted cash shown in Statements of Consolidated Cash Flows		235		370		274	381
Houston Electric [Member] | Other, net [Member]
Interest Income, Other		9		4		2
Houston Electric [Member] | Prepaid Expenses and Other Current Assets [Member]
Restricted cash		19		34
Houston Electric [Member] | Other Noncurrent Assets [Member]
Restricted cash		0		1
CERC Corp [Member]
Interest, net of capitalized interest		109		105		116
Income taxes (refunds), net		7		3		4
Accounts payable related to capital expenditures		86		80		56
Capital distribution associated with the Internal Spin		28	[4],[5]	1,473	[5]	0
ROU Asset Obtained In Exchange for Operating Lease Liability, Including Transition Impact of ASC 842 Adoption		29	[1]	0		0
Cash and cash equivalents		2		14
Total cash, cash equivalents and restricted cash shown in Statements of Consolidated Cash Flows		2		25		$ 12	$ 1
CERC Corp [Member] | Prepaid Expenses and Other Current Assets [Member]
Restricted cash		0		11
CERC Corp [Member] | Other Noncurrent Assets [Member]
Restricted cash		0		0
Bond Companies [Member] | Houston Electric [Member]
Cash and cash equivalents		$ 216		$ 335

[1] Includes the transition impact of adoption of ASU 2016-02 Leases as of January 1, 2019. The Registrants elected not to recast comparative periods in the year of adoption as permitted by the standard.

[2] CenterPoint Energy’s Cash and cash equivalents as of December 31, 2018 included $3.9 billion of temporary investments resulting from the Merger financings. CenterPoint Energy recorded interest income of $22 million, $28 million and $2 million for the years ended December 31, 2019, 2018 and 2017, respectively, in Other, net on CenterPoint Energy’s Statements of Consolidated Income. See Notes 13 and 14 for further details related to the Merger financings.

[3] Houston Electric’s Cash and cash equivalents as of December 31, 2019 and 2018 included $216 million and $335 million, respectively, of cash related to the Bond Companies. Houston Electric recorded interest income of $9 million, $4 million and $2 million for the years ended December 31, 2019, 2018 and 2017, respectively, in Other, net on Houston Electric’s Statement of Consolidated Income.

[4] The capital distribution in 2019 associated with the Internal Spin is a result of the return to accrual for the periods of CERC’s ownership during 2018.

[5] The capital distribution in 2019 associated with the Internal Spin is a result of the return to accrual for the periods of CERC’s ownership during 2018.

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Equity (CenterPoint Energy) (Details)																12 Months Ended
		Oct. 17, 2019 USD ($) $ / shares	Jul. 31, 2019 USD ($) $ / shares	Apr. 25, 2019 USD ($) $ / shares	Dec. 12, 2018 USD ($) $ / shares	Oct. 23, 2018 USD ($) $ / shares	Oct. 01, 2018 USD ($) $ / shares shares	Aug. 22, 2018 USD ($) $ / shares shares	Jul. 26, 2018 USD ($) $ / shares	Apr. 26, 2018 USD ($) $ / shares	Dec. 13, 2017 USD ($) $ / shares	Oct. 25, 2017 USD ($) $ / shares	Jul. 27, 2017 USD ($) $ / shares	Apr. 27, 2017 USD ($) $ / shares	Jan. 05, 2017 USD ($) $ / shares	Dec. 31, 2019 USD ($) day $ / shares shares	Dec. 31, 2018 USD ($) $ / shares	Dec. 31, 2017 USD ($) $ / shares
Dividends declared per share | $ / shares																$ 0.86	$ 1.1200	$ 1.35
Preferred stock dividend requirement																$ 117,000,000	$ 35,000,000	$ 0
Preferred stock par value (in dollars per share) | $ / shares																$ 0.01	$ 0.01	$ 0.01
Proceeds from the issuance of Series A Preferred Stock, net								$ 790,000,000								$ 0	$ 1,740,000,000	$ 0
Proceeds from issuance of common stock																0	1,844,000,000	0
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance																(108,000,000)	(68,000,000)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax																1,000,000	0	0
Other comprehensive loss from unconsolidated affiliates, net of tax																(1,000,000)	0	0
Prior service cost (2)	[1]															1,000,000	1,000,000
Actuarial losses (2)	[1]															8,000,000	6,000,000
Tax benefit (expense)																(3,000,000)	6,000,000
Net current period other comprehensive income (loss)																10,000,000	(25,000,000)	3,000,000
Ending Balance																(98,000,000)	(108,000,000)	$ (68,000,000)
Enable Midstream Partners [Member]
Undistributed earnings from equity method investments included in retained earnings																$ 0	$ 31,000,000
Common Stock [Member]
Declaration Date		Oct. 17, 2019	Jul. 31, 2019	Apr. 25, 2019	Dec. 12, 2018	Oct. 23, 2018			Jul. 26, 2018	Apr. 26, 2018	Dec. 13, 2017	Oct. 25, 2017	Jul. 27, 2017	Apr. 27, 2017	Jan. 05, 2017
Record Date		Nov. 21, 2019	Aug. 15, 2019	May 16, 2019	Feb. 21, 2019	Nov. 15, 2018			Aug. 16, 2018	May 17, 2018	Feb. 15, 2018	Nov. 16, 2017	Aug. 16, 2017	May 16, 2017	Feb. 16, 2017
Payment Date		Dec. 12, 2019	Sep. 12, 2019	Jun. 13, 2019	Mar. 14, 2019	Dec. 13, 2018			Sep. 13, 2018	Jun. 14, 2018	Mar. 08, 2018	Dec. 08, 2017	Sep. 08, 2017	Jun. 09, 2017	Mar. 10, 2017
Dividends declared per share | $ / shares		$ 0.2875	$ 0.2875	$ 0.2875	$ 0.2875	$ 0.2775			$ 0.2775	$ 0.2775	$ 0.2775	$ 0.2675	$ 0.2675	$ 0.2675	$ 0.2675	$ 0.8625	$ 1.1200	$ 1.3475
Dividends declared		$ 144,000,000	$ 145,000,000	$ 144,000,000	$ 144,000,000	$ 139,000,000			$ 120,000,000	$ 120,000,000	$ 120,000,000	$ 116,000,000	$ 115,000,000	$ 115,000,000	$ 115,000,000	$ 433,000,000	$ 523,000,000	$ 581,000,000
Stock issued (in shares) | shares							69,633,027
Common stock issued per share price | $ / shares							$ 27.25
Proceeds from issuance of common stock							$ 1,844,000,000
Series A Preferred Stock [Member]
Declaration Date			Jul. 31, 2019		Dec. 12, 2018
Record Date			Aug. 15, 2019		Feb. 15, 2019
Payment Date			Sep. 03, 2019		Mar. 01, 2019
Dividends declared per share | $ / shares			$ 30.6250		$ 32.1563											$ 30.6250	$ 32.1563	$ 0.0000
Dividends declared			$ 24,000,000		$ 26,000,000											$ 24,000,000	$ 26,000,000
Preferred stock dividend requirement																$ 49,000,000	$ 18,000,000	$ 0
Stock issued (in shares) | shares								800,000
Preferred stock par value (in dollars per share) | $ / shares								$ 1,000								$ 0.01	$ 0.01
Preferred stock liquidation preference																$ 800,000,000	$ 800,000,000
Preferred stock liquidation preference (per share) | $ / shares																$ 1,000
Preferred stock dividend rate																6.125%
Preferred stock redemption price (per share) | $ / shares																$ 1,000
Preferred stock convertible threshold (in days) | day																120
Series B Preferred Stock [Member]
Declaration Date		Oct. 17, 2019	Jul. 31, 2019	Apr. 25, 2019	Dec. 12, 2018	Oct. 23, 2018
Record Date		Nov. 15, 2019	Aug. 15, 2019	May 15, 2019	Feb. 15, 2019	Nov. 15, 2018
Payment Date		Dec. 02, 2019	Sep. 03, 2019	Jun. 03, 2019	Mar. 01, 2019	Dec. 01, 2018
Dividends declared per share | $ / shares		$ 17.5000	$ 17.5000	$ 17.5000	$ 17.5000	$ 11.6667										$ 52.5000	$ 29.1667	$ 0.0000
Dividends declared		$ 17,000,000	$ 17,000,000	$ 17,000,000	$ 17,000,000	$ 11,000,000										$ 51,000,000	$ 28,000,000
Preferred stock dividend requirement																$ 68,000,000	$ 17,000,000	$ 0
Preferred stock par value (in dollars per share) | $ / shares																$ 0.01	$ 0.01
Preferred stock liquidation preference																$ 977,500,000	$ 977,500,000
Preferred stock liquidation preference (per share) | $ / shares																$ 1,000
Preferred stock dividend rate																7.00%
Proceeds from the issuance of Series B Preferred Stock, net							$ 950,000,000
Depositary Share, Conversion Ratio																0.05
Preferred Stock, Convertible, Conversion Price | $ / shares																$ 1,000
Preferred stock threshold consecutive calendar days | day																20
Depositary Share [Member]
Stock issued (in shares) | shares							19,550,000
Depositary share par value (in dollars per depositary share) | $ / shares							$ 50									$ 50
Number of depositary shares eligible for conversion (in shares) | shares																20
120 Days After Conclusion of Review or Appeal [Member] | Series A Preferred Stock [Member]
Preferred stock redemption price (per share) | $ / shares																$ 1,020
Preferred stock redemption percentage liquidation value																102.00%
London Interbank Offered Rate (LIBOR) [Member] | Series A Preferred Stock [Member]
Preferred stock dividend rate																3.27%
Over-Allotment Option [Member] | Common Stock [Member]
Stock issued (in shares) | shares							9,082,568
Over-Allotment Option [Member] | Series B [Member]
Stock issued (in shares) | shares							2,550,000
Minimum [Member] | Series B Preferred Stock [Member]
Preferred Stock, Convertible, Stock Price Trigger | $ / shares																$ 27.2494
Conversion rate per share | shares																30.5820
Minimum [Member] | Series B [Member]
Preferred Stock, Convertible, Stock Price Trigger | $ / shares																$ 27.2494
Minimum [Member] | Depositary Share [Member]
Conversion rate per share | shares																1.5291
Maximum [Member] | Series B Preferred Stock [Member]
Preferred Stock, Convertible, Stock Price Trigger | $ / shares																$ 32.6990
Conversion rate per share | shares																36.6980
Maximum [Member] | Series B [Member]
Preferred Stock, Convertible, Stock Price Trigger | $ / shares																$ 32.6990
Maximum [Member] | Depositary Share [Member]
Conversion rate per share | shares																1.8349
Interest Rate Contract [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Other comprehensive income (loss) before reclassifications:	[2]															$ (3,000,000)	(19,000,000)
Cash Flow Hedging [Member] | Interest Rate Contract [Member] | Interest Expense [Member]
Gain (loss) reclassified from accumulated OCI into income																1,000,000	1,000,000
Houston Electric [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance																(14,000,000)	0
Prior service cost (2)	[1]															0	0
Actuarial losses (2)	[1]															0	0
Tax benefit (expense)																0	4,000,000
Net current period other comprehensive income (loss)																(1,000,000)	(14,000,000)	(1,000,000)
Ending Balance																(15,000,000)	(14,000,000)	0
Houston Electric [Member] | Interest Rate Contract [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Other comprehensive income (loss) before reclassifications:	[2]															(1,000,000)	(18,000,000)
Houston Electric [Member] | Cash Flow Hedging [Member] | Interest Rate Contract [Member] | Interest Expense [Member]
Gain (loss) reclassified from accumulated OCI into income																1,000,000	1,000,000
CERC Corp [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance																5,000,000	6,000,000
Prior service cost (2)	[1]															0	1,000,000
Actuarial losses (2)	[1]															0	0
Tax benefit (expense)																(2,000,000)	(1,000,000)
Net current period other comprehensive income (loss)																5,000,000	0	3,000,000
Ending Balance																10,000,000	5,000,000	$ 6,000,000
CERC Corp [Member] | Interest Rate Contract [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Other comprehensive income (loss) before reclassifications:	[2]															0	(1,000,000)
CERC Corp [Member] | Cash Flow Hedging [Member] | Interest Rate Contract [Member] | Interest Expense [Member]
Gain (loss) reclassified from accumulated OCI into income																1,000,000	1,000,000
Pension and Other Postretirement Plans [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Other comprehensive income (loss) before reclassifications:																7,000,000	(19,000,000)
Pension and Other Postretirement Plans [Member] | Houston Electric [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Other comprehensive income (loss) before reclassifications:																0	0
Pension and Other Postretirement Plans [Member] | CERC Corp [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Other comprehensive income (loss) before reclassifications:																7,000,000	1,000,000
Adoption of ASU 2018-02 [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Adoption of ASU 2018-02																0	(15,000,000)
Adoption of ASU 2018-02 [Member] | Houston Electric [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Adoption of ASU 2018-02																0	0
Adoption of ASU 2018-02 [Member] | CERC Corp [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Adoption of ASU 2018-02																$ 0	$ (1,000,000)

[1] Amounts are included in the computation of net periodic cost and are reflected in Other, net in each of the Registrants’ respective Statements of Consolidated Income.

[2] Gains and losses are reclassified from Accumulated other comprehensive income into income when the hedged transactions affect earnings. The reclassification amounts are included in Interest and other finance charges in each of the Registrant’s respective Statements of Consolidated Income. Amounts are $1 million and less than $1 million for the years ended December 31, 2019 and 2018, respectively.

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Stock-Based Incentive Compensation Plans and Employee Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2019

Defined Benefit Plan Disclosure [Line Items]

Schedule of Compensation Cost for Share-based Payment Arrangements, Allocation of Share-based Compensation Costs by Plan [Table Text Block]

The following table summarizes CenterPoint Energy’s expenses related to LTIPs for 2019, 2018 and 2017:

	Year Ended December 31,
	2019		2018		2017
	(in millions)
LTIP Compensation expense (1)	$	28	$	26	$	21
Income tax benefit recognized	7		6		8
Actual tax benefit realized for tax deductions	12		5		6

(1)

Amounts presented in the table above are included in Operation and maintenance expense in CenterPoint Energy’s Statements of Consolidated Income and shown prior to any amounts capitalized.

Share-Based Compensation, Activity [Table Text Block]

The following tables summarize CenterPoint Energy’s LTIP activity for 2019:

	Year Ended December 31, 2019
	Shares (Thousands)		Weighted-Average Grant Date Fair Value		Remaining Average Contractual Life (Years)	Aggregate Intrinsic Value (2) (Millions)
Performance Awards (1)
Outstanding and non-vested as of December 31, 2018	3,818		$	23.91
Granted	1,413		31.16
Forfeited or canceled	(825	)	24.78
Vested and released to participants	(1,074	)	18.97
Outstanding and non-vested as of December 31, 2019	3,332		$	28.36	1.1	$	53
Stock Unit Awards
Outstanding and non-vested as of December 31, 2018	1,060		$	24.08
Granted	470		31.07
Forfeited or canceled	(131	)	27.95
Vested and released to participants	(433	)	20.72
Outstanding and non-vested as of December 31, 2019	966		$	28.46	1.2	$	26

 

(1) Reflects maximum performance achievement.

(2) Reflects the impact of current expectations of achievement and stock price.

Share-Based Compensation Arrangement By Award, Weighted Average Grant Date Fair Value, Grant Date Intrinsic Value, and Vested Grant Date Fair Value [Table Text Block]

The weighted average grant date fair values per unit of awards granted were as follows for 2019, 2018 and 2017:

	Year Ended December 31,
	2019		2018		2017
	(In millions, except for per unit amounts)
Performance Awards
Weighted-average grant date fair value per unit of awards granted	$	31.16	$	26.74	$	26.64
Total intrinsic value of awards received by participants	36		12		7
Vested grant date fair value	20		9		5
Stock Unit Awards
Weighted-average grant date fair value per unit of awards granted	$	31.07	$	26.62	$	26.77
Total intrinsic value of awards received by participants	15		9		9
Vested grant date fair value	9		7		7

Schedule of Multiemployer Plans [Table Text Block]

CenterPoint Energy’s participation in the significant plans is outlined in the following table. The EIN / Pension Plan Number column provides the EIN and three-digit pension plan numbers. The most recent Pension Protection Act Zone Status available in 2019 is for the plan year end at January 31, 2019 for the Central Pension Fund, May 31, 2019 for the Indiana Pension Laborers Fund, December 31, 2018 for the Pipeline Industry Benefit Fund, December 31, 2018 for the Laborers District Council & Contractors’ Pension Fund of Ohio, April 30, 2019 for the Ohio Operating Engineers Pension Fund, April 30, 2019 for the Operating Engineers Local 324 Fringe Benefit Fund, December 31, 2018 for the Minnesota Laborers Pension Fund, and December 31, 2018 for the Laborers’ Combined Fund of Western Pennsylvania. Generally, plans in the red zone are less than 65% funded, plans in the yellow zone are less than 80% funded and plans in the green zone are at least 80% funded. The FIP/RP Status Pending / Implemented column indicates plans for which a FIP or RP is either pending or has been implemented. The multi-employer contributions listed in the table below are CenterPoint Energy’s multi-employer contributions made in 2019.

Federal law requires pensio

Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block]

Amounts recognized in accumulated other comprehensive loss (gain) consist of the following:

	December 31,
	2019								2018
	Pension Benefits		Postretirement Benefits						Pension Benefits		Postretirement Benefits
	CenterPoint Energy		CenterPoint Energy			CERC			CenterPoint Energy		CenterPoint Energy			CERC
	(in millions)
Unrecognized actuarial loss (gain)	$	105	$	(16	)	$	(12	)	$	109	$	(7	)	$	(3	)
Unrecognized prior service cost	—		7			7			1		5			5
Deferred tax benefit	—		—			—			—		—			(9		)
Net amount recognized in accumulated other comprehensive loss (gain)	$	105	$	(9	)	$	(5	)	$	110	$	(2	)	$	(7	)

Changes in accumulated comprehensive income (loss) are as follows:

	Year Ended December 31,
	2019									2018
	CenterPoint Energy			Houston Electric			CERC			CenterPoint Energy			Houston Electric			CERC
	(in millions)
Beginning Balance	$	(108	)	$	(14	)	$	5		$	(68	)	$	—		$	6
Other comprehensive income (loss) before reclassifications:
Remeasurement of pension and other postretirement plans	7			—			7			(19		)	—			1
Deferred loss from interest rate derivatives (1)	(3		)	(1		)	—			(19		)	(18		)	(1		)
Reclassified to earnings	1			—			—			—			—			—
Other comprehensive loss from unconsolidated affiliates	(1		)	—			—			—			—			—
Amounts reclassified from accumulated other comprehensive loss:
Prior service cost (2)	1			—			—			1			—			1
Actuarial losses (2)	8			—			—			6			—			—
Tax benefit (expense)	(3		)	—			(2		)	6			4			(1		)
Net current period other comprehensive income (loss)	10			(1		)	5			(25		)	(14		)	—
Adoption of ASU 2018-02	—			—			—			(15		)	—			(1		)
Ending Balance	$	(98	)	$	(15	)	$	10		$	(108	)	$	(14	)	$	5

(1) Gains and losses are reclassified from Accumulated other comprehensive income into income when the hedged transactions affect earnings. The reclassification amounts are included in Interest and other finance charges in each of the Registrant’s respective Statements of Consolidated Income. Amounts are $1 million and less than $1 million for the years ended December 31, 2019 and 2018, respectively.

(2)

Amounts are included in the computation of net periodic cost and are reflected in Other, net in each of the Registrants’ respective Statements of Consolidated Income.

Schedule of Defined Benefit Plan Amounts Recognized in Other Comprehensive Income (Loss) [Table Text Block]

The changes in plan assets and benefit obligations recognized in other comprehensive income during 2019 are as follows:

	Pension Benefits			Postretirement Benefits
	CenterPoint Energy			CenterPoint Energy			CERC
	(in millions)
Net loss (gain)	$	4		$	(8	)	$	(6	)
Amortization of net loss	(8		)	—			—
Amortization of prior service cost	(1		)	1			(1		)
Total recognized in comprehensive income	$	(5	)	$	(7	)	$	(7	)
Total expense recognized in net periodic costs and Other comprehensive income	$	87		$	1		$	(1	)

Benefit Plan Contributions [Table Text Block]

The Registrants made the following contributions in 2019 and expect to make the following minimum contributions in 2020 to the indicated benefit plans below:

	Contributions in 2019						Expected Minimum Contributions in 2020
	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC
	(in millions)
Qualified pension plans	$	86	$	—	$	—	$	76	$	—	$	—
Non-qualified pension plans	23		—		—		7		—		—
Postretirement benefit plans	17		10		3		17		9		3

Schedule of Expected Benefit Payments [Table Text Block]

The following benefit payments are expected to be paid by the pension and postretirement benefit plans:

	Pension Benefits		Postretirement Benefits
	CenterPoint Energy		CenterPoint Energy		Houston Electric		CERC
	(in millions)
2020	$	180	$	18	$	8	$	5
2021	178		18		8		4
2022	180		19		9		5
2023	181		20		10		5
2024	177		21		10		6
2025-2029	824		112		54		30

Defined Contribution Plan Disclosures [Table Text Block]

CenterPoint Energy allocates the savings plan benefit expense to Houston Electric and CERC related to their respective employees. The following table summarizes the Registrants’ savings plan benefit expense for 2019, 2018 and 2017:

	Year Ended December 31,
	2019						2018						2017
	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC
	(in millions)
Savings plan benefit  expenses (1)	$	58	$	18	$	18	$	43	$	17	$	18	$	41	$	17	$	17

Other Benefit Plans [Table Text Block]

Expenses related to other benefit plans were recorded as follows:

	Year Ended December 31,
	2019						2018						2017
	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC
	(in millions)
Postemployment benefits	$	2	$	1	$	1	$	3	$	4	$	1	$	6	$	1	$	4
Deferred compensation plans	4		1		—		3		1		—		3		1		—

Amounts related to other benefit plans were included in Benefit Obligations in the Registrants’ accompanying Consolidated Balance Sheets as follows:

	December 31, 2019						December 31, 2018
	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC
	(in millions)
Postemployment benefits	$	11	$	3	$	7	$	11	$	3	$	7
Deferred compensation plans	41		8		3		42		9		3
Split-dollar life insurance arrangements	32		1		—		36		1		—

Other Employee Matters [Table Text Block]

As of December 31, 2019, the Registrants’ employees were covered by collective bargaining agreements as follows:

		Percentage of Employees Covered
	Agreement Expiration	CenterPoint Energy		Houston Electric		CERC
IBEW Local 66	May 2020	10	%	51	%	—
OPEIU Local 12 and Mankato	March and May 2021	2	%	—		3	%
Gas Workers Union Local 340	April 2020	3	%	—		12	%
IBEW Locals 949 & 1393 and USW Locals 12213 & 7441	December 2020	4	%	—		7	%
USW Locals 13-227 & 13-1 and IBEW Local 702	June and July 2022	5	%	—		12	%
Teamsters Local 135	September 2021	—		—		—
UWUA Local 175	October 2021	1	%	—		—
Trade Agreements of Infrastructure Services through the DCA and PLCA (1)	Various expiration dates in 2020–2022	27	%	—		—
Total		52	%	51	%	34	%

(1)

Infrastructure Services negotiates various trade agreements through contractor associations. The two primary associations are the DCA and the PLCA.  These trade agreements are with a variety of construction unions including Laborer’s International Union of North America, International Union of Operating Engineers, United Association of Journeymen and Apprentices of the Plumbing and Pipe Fitting Industry, and Teamsters. The trade agreements have varying expiration dates in 2020, 2021 and 2022. In addition, these subsidiaries have various project agreements and small local agreements.  These agreements expire upon completion of a specific project or on various dates throughout the year.

Pension Plan [Member]

Defined Benefit Plan Disclosure [Line Items]

Schedule of Net Benefit Costs [Table Text Block]

CenterPoint Energy’s net periodic cost includes the following components relating to pension, including the non-qualified benefit plans:

	Year Ended December 31,
	2019			2018			2017
	(in millions)
Service cost (1)	$	40		$	37		$	36
Interest cost (2)	96			79			89
Expected return on plan assets (2)	(105		)	(107		)	(97		)
Amortization of prior service cost (2)	9			9			9
Amortization of net loss (2)	52			43			58
Settlement cost (2) (3)	2			—			—
Curtailment gain (2) (4)	(1		)	—			—
Net periodic cost	$	93		$	61		$	95

 

(1) Amounts presented in the table above are included in Operation and maintenance expense in CenterPoint Energy’s Statements of Consolidated Income, net of regulatory deferrals and amounts capitalized.

(2) Amounts presented in the table above are included in Other, net in CenterPoint Energy’s Statements of Consolidated Income, net of regulatory deferrals.

(3) A one-time, non-cash settlement cost is required when the total lump sum distributions or other settlements of plan benefit obligations during a plan year exceed the service cost and interest cost components of the net periodic cost for that year. In 2019, CenterPoint Energy recognized a non-cash settlement cost due to lump sum settlement payments.

(4) A curtailment gain or loss is required when the expected future services of a significant number of employees are reduced or eliminated for the accrual of benefits. In 2019, CenterPoint Energy recognized a pension curtailment gain related to employees who were terminated after the Merger closed.

Schedule of Assumptions Used [Table Text Block]

CenterPoint Energy used the following assumptions to determine net periodic cost relating to pension benefits:

	Year Ended December 31,
	2019		2018		2017
Discount rate	4.35	%	3.65	%	4.15	%
Expected return on plan assets	6.00		6.00		6.00
Rate of increase in compensation levels	4.60		4.45		4.50

Schedule of Net Pension and Post-retirement Benefit Costs [Table Text Block]

The following table summarizes changes in the benefit obligation, plan assets, the amounts recognized in the Consolidated Balance Sheets as well as the key assumptions of CenterPoint Energy’s pension plans. The measurement dates for plan assets and obligations were December 31, 2019 and 2018.

	December 31,
	2019			2018
	(in millions, except for actuarial assumptions)
Change in Benefit Obligation
Benefit obligation, beginning of year	$	2,013		$	2,225
Plan obligations assumed in Merger	332			—
Service cost	40			37
Interest cost	96			79
Benefits paid	(244		)	(201		)
Actuarial (gain) loss (1)	216			(127		)
Plan amendment	1			—
Curtailment	(1		)	—
Benefit obligation, end of year	2,453			2,013
Change in Plan Assets
Fair value of plan assets, beginning of year	1,516			1,801
Plan assets assumed in Merger	286			—
Employer contributions	109			69
Benefits paid	(244		)	(201		)
Actual investment return	338			(153		)
Fair value of plan assets, end of year	2,005			1,516
Funded status, end of year	$	(448	)	$	(497	)
Amounts Recognized in Balance Sheets
Current liabilities-other	$	(8	)	$	(7	)
Other liabilities-benefit obligations	(440		)	(490		)
Net liability, end of year	$	(448	)	$	(497	)
Actuarial Assumptions
Discount rate (2)	3.20		%	4.35		%
Expected return on plan assets (3)	5.75			6.00
Rate of increase in compensation levels	4.95			4.60
Interest crediting rate	3.25			3.75

(1) Significant sources of loss for 2019 include the decrease in discount rate from 4.35% to 3.20%. Significant sources of gain for 2018 include the increase in discount rate from 3.65% to 4.35% and the mortality projection scale change from MP2017 to MP2018.

(2) The discount rate assumption was determined by matching the projected cash flows of CenterPoint Energy’s plans against a hypothetical yield curve of high-quality corporate bonds represented by a series of annualized individual discount rates from one-half to 99 years.

(3)

The expected rate of return assumption was developed using the targeted asset allocation of CenterPoint Energy’s plans and the expected return for each asset class.

Schedule of Accumulated Benefit Obligations in Excess of Fair Value of Plan Assets [Table Text Block]

The following table displays pension benefits related to CenterPoint Energy’s pension plans that have accumulated benefit obligations in excess of plan assets:

	December 31,
	2019				2018
	Pension (Qualified)		Pension (Non-qualified)		Pension (Qualified)		Pension (Non-qualified)
	(in millions)
Accumulated benefit obligation	$	2,352	$	68	$	1,930	$	61
Projected benefit obligation	2,385		68		1,952		61
Fair value of plan assets	2,005		—		1,516		—

Target Allocation of Plan Assets [Table Text Block]

As part of the investment strategy discussed above, CenterPoint Energy maintained the following weighted average allocation targets for its pension plans as of December 31, 2019:

	Minimum		Maximum
U.S. equity	19	%	29	%
International equity	8	%	18	%
Real estate	3	%	9	%
Fixed income	52	%	62	%
Cash	0	%	2	%

Schedule of Allocation of Plan Assets [Table Text Block]

The following tables set forth by level, within the fair value hierarchy (see Note 10), CenterPoint Energy’s pension plan assets at fair value as of December 31, 2019 and 2018:

	Fair Value Measurements as of December 31,
	2019										2018
	(Level 1)			(Level 2)		(Level 3)		Total			(Level 1)			(Level 2)		(Level 3)		Total
	(in millions)
Cash	$	(7	)	$	—	$	—	$	(7	)	$	19		$	—	$	—	$	19
Corporate bonds:
Investment grade or above	—			699		—		699			—			368		—		368
Equity securities:
U.S. companies	69			—		—		69			60			—		—		60
Cash received as collateral from securities lending	61			—		—		61			77			—		—		77
U.S. treasuries	232			—		—		232			196			—		—		196
Mortgage backed securities	—			8		—		8			—			6		—		6
Asset backed securities	—			3		—		3			—			1		—		1
Municipal bonds	—			44		—		44			—			27		—		27
Mutual funds (2)	270			—		—		270			167			—		—		167
International government bonds	—			21		—		21			—			16		—		16
Obligation to return cash received as collateral from securities lending	(61		)	—		—		(61		)	(77		)	—		—		(77		)
Total investments at fair value	$	564		$	775	$	—	$	1,339		$	442		$	418	$	—	$	860
Investments measured by net asset value per share or its equivalent (1) (2)								666										656
Total Investments								$	2,005									$	1,516

(1) Represents investments in common collective trust funds.

(2) The amounts invested in mutual funds and common collective trust funds were allocated as follows:

	As of December 31,
	2019				2018
	Mutual Funds		Common Collective Trust Funds		Mutual Funds		Common Collective Trust Funds
International equities (1)	31	%	29	%	85	%	41	%
U.S. equities	49	%	51	%	15	%	5	%
Real estate	1	%	6	%	—	%	—	%
Fixed income	19	%	14	%	—	%	54	%

Postretirement Benefits [Member]

Defined Benefit Plan Disclosure [Line Items]

Schedule of Net Benefit Costs [Table Text Block]

Postretirement benefits are accrued over the active service period of employees. The net postretirement benefit cost includes the following components:

	Year Ended December 31,
	2019									2018									2017
	CenterPoint Energy			Houston Electric			CERC			CenterPoint Energy			Houston Electric			CERC			CenterPoint Energy			Houston Electric			CERC
	(in millions)
Service cost (1)	$	3		$	1		$	1		$	2		$	—		$	1		$	2		$	1		$	1
Interest cost (2)	15			7			5			13			8			4			16			9			5
Expected return on plan assets (2)	(5		)	(4		)	(1		)	(5		)	(4		)	(1		)	(5		)	(4		)	(1		)
Amortization of prior service cost (credit) (2)	(5		)	(6		)	1			(5		)	(5		)	1			(5		)	(6		)	1
Net postretirement benefit cost (credit)	$	8		$	(2	)	$	6		$	5		$	(1	)	$	5		$	8		$	—		$	6

(1) Amounts presented in the table above are included in Operation and maintenance expense in each of the Registrants’ respective Statements of Consolidated Income, net of regulatory deferrals and amounts capitalized.

(2) Amounts presented in the table above are included in Other, net in each of the Registrants’ respective Statements of Consolidated Income, net of regulatory deferrals.

Schedule of Assumptions Used [Table Text Block]

The following assumptions were used to determine net periodic cost relating to postretirement benefits:

	Year Ended December 31,
	2019						2018						2017
	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC
Discount rate	3.20	%	3.20	%	3.20	%	3.60	%	3.60	%	3.60	%	4.15	%	4.15	%	4.15	%
Expected return on plan assets	4.60		4.70		4.15		4.55		4.75		3.85		4.50		4.75		3.60

Schedule of Net Pension and Post-retirement Benefit Costs [Table Text Block]

The following table summarizes changes in the benefit obligation, plan assets, the amounts recognized in consolidated balance sheets and the key assumptions of the postretirement plans. The measurement dates for plan assets and benefit obligations were December 31, 2019 and 2018.

	December 31,
	2019									2018
	CenterPoint Energy			Houston Electric			CERC			CenterPoint Energy			Houston Electric			CERC
	(in millions)
Change in Benefit Obligation
Benefit obligation, beginning of year	$	331		$	166		$	110		$	386		$	225		$	109
Plan obligations assumed in Merger	37			—			—			—			—			—
Service cost	3			1			1			2			—			1
Interest cost	15			7			5			13			8			4
Participant contributions	8			2			4			7			2			4
Benefits paid	(26		)	(13		)	(8		)	(25		)	(13		)	(9		)
Plan amendment	9			3			5			—			—			—
Actuarial (gain) loss (1)	(21		)	(4		)	(15		)	(52		)	(56		)	1
Benefit obligation, end of year	356			162			102			331			166			110
Change in Plan Assets
Fair value of plan assets, beginning of year	114			89			25			120			93			26
Employer contributions	17			10			3			14			9			4
Participant contributions	8			2			4			7			2			4
Benefits paid	(26		)	(13		)	(8		)	(25		)	(13		)	(9		)
Actual investment return	15			13			3			(2		)	(2		)	—
Fair value of plan assets, end of year	128			101			27			114			89			25
Funded status, end of year	$	(228	)	$	(61	)	$	(75	)	$	(217	)	$	(77	)	$	(85	)
Amounts Recognized in Balance Sheets
Current liabilities-other	$	(8	)	$	—		$	(3	)	$	(6	)	$	—		$	(3	)
Other liabilities-benefit obligations	(220		)	(61		)	(72		)	(211		)	(77		)	(82		)
Net liability, end of year	$	(228	)	$	(61	)	$	(75	)	$	(217	)	$	(77	)	$	(85	)
Actuarial Assumptions
Discount rate (2)	3.25		%	3.25		%	3.25		%	4.35		%	4.35		%	4.35		%
Expected return on plan assets (3)	3.95			4.05			3.35			4.60			4.70			4.15
Medical cost trend rate assumed for the next year - Pre-65	5.50			5.50			5.50			5.95			5.95			5.95
Medical/prescription drug cost trend rate assumed for the next year - Post-65	5.75			5.75			5.75			28.60			28.60			28.60
Prescription drug cost trend rate assumed for the next year - Pre-65	8.00			8.00			8.00			9.20			9.20			9.20
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)	4.50			4.50			4.50			4.50			4.50			4.50
Year that the cost trend rates reach the ultimate trend rate - Pre-65	2028			2028			2028			2026			2026			2026
Year that the cost trend rates reach the ultimate trend rate - Post-65	2029			2029			2029			2027			2027			2027

(1) Significant sources of gain for 2019 include favorable cost trend rates and benefit claims experience in addition to the change in mortality projection scale from MP2018 to MP2019. Significant sources of gain for 2018 include the increase in the discount rate from 3.60% to 4.35%, favorable benefit claims experience and cost trend rates in addition to the change in mortality projection scale from MP2017 to MP2018.

(2) The discount rate assumption was determined by matching the projected cash flows of the plans against a hypothetical yield curve of high-quality corporate bonds represented by a series of annualized individual discount rates from one-half to 99 years.

(3) The expected rate of return assumption was developed using the targeted asset allocation of the plans and the expected return for each asset class.

Target Allocation of Plan Assets [Table Text Block]

As part of the investment strategy discussed above, the Registrants maintained the following weighted average allocation targets for the postretirement plans as of December 31, 2019:

	CenterPoint Energy				Houston Electric				CERC
	Minimum		Maximum		Minimum		Maximum		Minimum		Maximum
U.S. equity	13	%	23	%	13	%	23	%	15	%	25	%
International equity	3	%	13	%	3	%	13	%	2	%	12	%
Fixed income	69	%	79	%	69	%	79	%	68	%	78	%
Cash	0	%	2	%	0	%	2	%	0	%	2	%

Schedule of Allocation of Plan Assets [Table Text Block]

The following table presents mutual funds by level, within the fair value hierarchy, the Registrants’ postretirement plan assets at fair value as of December 31, 2019 and 2018:

	Fair Value Measurements as of December 31,
	2019								2018
	Mutual Funds
	(Level 1)		(Level 2)		(Level 3)		Total		(Level 1)		(Level 2)		(Level 3)		Total
	(in millions)
CenterPoint Energy	$	128	$	—	$	—	$	128	$	114	$	—	$	—	$	114
Houston Electric	101		—		—		101		89		—		—		89
CERC	27		—		—		27		25		—		—		25

The amounts invested in mutual funds were allocated as follows:

	As of December 31,
	2019						2018
	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC
Fixed income	71	%	71	%	69	%	74	%	74	%	73	%
U.S. equities	21	%	21	%	24	%	19	%	19	%	21	%
International equities	8	%	8	%	7	%	7	%	7	%	6	%

XML

Indexed Debt Securities (ZENS) and Securities Related to ZENS (CenterPoint Energy) (Tables)

12 Months Ended

Dec. 31, 2019

Indexed Debt Securities [Abstract]

Summarized Financial Information on Investment in Time Warner Securities and Indexed Debt Security Obligation [Table Text Block]

A subsidiary of CenterPoint Energy holds shares of certain securities detailed in the table below, which are classified as trading securities and are expected to be held to facilitate CenterPoint Energy’s ability to meet its obligation under the ZENS. Unrealized gains and losses resulting from changes in the market value of the ZENS-Related Securities are recorded in CenterPoint Energy’s Statements of Consolidated Income.

	Shares Held at December 31,
	2019	2018
AT&T Common	10,212,945	10,212,945
Charter Common	872,503	872,912

CenterPoint Energy’s reference shares for each ZENS consisted of the following:

	December 31,
	2019	2018
	(in shares)
AT&T Common	0.7185	0.7185
Charter Common	0.061382	0.061382

The following table sets forth summarized financial information regarding CenterPoint Energy’s investment in ZENS-Related Securities and each component of CenterPoint Energy’s ZENS obligation. 

	ZENS-Related Securities			Debt Component of ZENS			Derivative Component of ZENS
	(in millions)
Balance as of December 31, 2016	$	953		$	114		$	717
Accretion of debt component of ZENS	—			27			—
2% interest paid	—			(17		)	—
Distribution to ZENS holders	—			(2		)	—
Gain on indexed debt securities	—			—			(49		)
Gain on ZENS-Related Securities	7			—			—
Balance as of December 31, 2017	960			122			668
Accretion of debt component of ZENS	—			21			—
2% interest paid	—			(17		)	—
Sale of ZENS-Related Securities	(398		)	—			—
Distribution to ZENS holders	—			(102		)	(46		)
Gain on indexed debt securities	—			—			(21		)
Loss on ZENS-Related Securities	(22		)	—			—
Balance as of December 31, 2018	540			24			601
Accretion of debt component of ZENS	—			17			—
2% interest paid	—			(17		)	—
Distribution to ZENS holders	—			(5		)	—
Loss on indexed debt securities	—			—			292
Gain on ZENS-Related Securities	282			—			—
Balance as of December 31, 2019	$	822		$	19		$	893

XML

Stock-Based Incentive Compensation Plans and Employee Benefit Plans Pension and Postretirement Benefits (Details) - USD ($) $ in Millions						12 Months Ended
		Dec. 31, 2019		Dec. 31, 2018		Dec. 31, 2019		Dec. 31, 2018		Dec. 31, 2017
Amounts recognized in balance sheets
Other liabilities-benefit obligations		$ (754)		$ (796)		$ (754)		$ (796)
Changes in plan assets and benefit obligations recognized in other comprehensive income
Amortization of net loss	[1]					(8)		(6)
Prior service cost (2)	[1]					(1)		(1)
Other Postretirement Benefits Plan [Member]
Components of net periodic costs [Abstract]
Service cost (1)	[2]					3		2		$ 2
Interest cost (2)	[3]					15		13		16
Expected return on plan assets (2)	[3]					(5)		(5)		(5)
Amortization of prior service cost (2)	[3]					(5)		(5)		(5)
Net periodic cost (credit)						$ 8		$ 5		$ 8
Assumptions used to determine net periodic benefit (income) cost
Discount rate						3.20%		3.60%		4.15%
Expected return on plan assets		3.95%	[4]	4.60%	[4]	4.60%		4.55%		4.50%
Change in benefit obligation [Roll Forward]
Benefit obligation, beginning of year						$ 331		$ 386
Plan obligations assumed in Merger						37		0
Service cost (1)	[2]					3		2		$ 2
Interest cost (2)	[3]					15		13		16
Participant contributions						8		7
Benefits paid						(26)		(25)
Plan amendment						9		0
Actuarial (gain) loss (1)	[5]					(21)		(52)
Benefit obligation, end of year		$ 356		$ 331		356		331		386
Change in plan assets [Rollforward]
Fair value of plan assets, beginning of year						114		120
Employer contributions						17		14
Participant contributions						8		7
Benefits paid						(26)		(25)
Actual investment return						15		(2)
Fair value of plan assets, end of year		128		114		128		114		$ 120
Funded status of plan
Funded status, end of year		(228)		(217)		(228)		(217)
Amounts recognized in balance sheets
Current liabilities-other		(8)		(6)		(8)		(6)
Other liabilities-benefit obligations		(220)		(211)		(220)		(211)
Net liability, end of year		$ (228)		$ (217)		$ (228)		$ (217)
Discount rate (2)		3.25%	[6]	4.35%	[6]	3.25%	[6]	4.35%	[6]	3.60%
Expected return on plan assets (3)		3.95%	[4]	4.60%	[4]	4.60%		4.55%		4.50%
Prescription drug cost trend rate assumed for the next year - Pre-65						8.00%		9.20%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)		4.50%		4.50%		4.50%		4.50%
Annualized individual discount rates based on time period, minimum						6 months
Annualized individual discount rates based on time period, maximum						99 years
Amounts recognized in accumulated other comprehensive loss
Unrecognized actuarial loss (gain)		$ (16)		$ (7)		$ (16)		$ (7)
Unrecognized prior service cost		7		5		7		5
Deferred Tax Benefit On Accumulated Other Comprehensive Income		0		0		0		0
Net amount recognized in accumulated other comprehensive loss (gain)		$ (9)		$ (2)		(9)		(2)
Changes in plan assets and benefit obligations recognized in other comprehensive income
Net loss (gain)						(8)
Amortization of net loss						0
Prior service cost (2)						1
Total recognized in comprehensive income						(7)
Total expense recognized in net periodic cost and other comprehensive income						1
Pension Plan [Member]
Components of net periodic costs [Abstract]
Service cost (1)						40		37
Interest cost (2)						96		79
Net periodic cost (credit)						$ 93		$ 61		$ 95
Assumptions used to determine net periodic benefit (income) cost
Discount rate						4.35%		3.65%		4.15%
Expected return on plan assets		5.75%	[7]	6.00%	[7]	6.00%		6.00%		6.00%
Rate of increase in compensation levels						4.60%		4.45%		4.50%
Change in benefit obligation [Roll Forward]
Benefit obligation, beginning of year						$ 2,013		$ 2,225
Plan obligations assumed in Merger						332		0
Service cost (1)						40		37
Interest cost (2)						96		79
Benefits paid						(244)		(201)
Plan amendment						1		0
Actuarial (gain) loss (1)	[8]					216		(127)
Curtailment						(1)		0
Benefit obligation, end of year		$ 2,453		$ 2,013		2,453		2,013		$ 2,225
Change in plan assets [Rollforward]
Fair value of plan assets, beginning of year						1,516		1,801
Plan assets assumed in Merger						286		0
Employer contributions						109		69
Benefits paid						(244)		(201)
Actual investment return						338		(153)
Fair value of plan assets, end of year		2,005		1,516		2,005		1,516		$ 1,801
Funded status of plan
Funded status, end of year		(448)		(497)		(448)		(497)
Amounts recognized in balance sheets
Current liabilities-other		(8)		(7)		(8)		(7)
Other liabilities-benefit obligations		(440)		(490)		(440)		(490)
Net liability, end of year		$ (448)		$ (497)		$ (448)		$ (497)
Discount rate (2)		3.20%	[9]	4.35%	[9]	3.20%	[9]	4.35%	[9]	3.65%
Expected return on plan assets (3)		5.75%	[7]	6.00%	[7]	6.00%		6.00%		6.00%
Rate of increase in compensation levels		4.95%		4.60%		4.95%		4.60%
Interest crediting rate		3.25%		3.75%		3.25%		3.75%
Annualized individual discount rates based on time period, minimum						6 months
Annualized individual discount rates based on time period, maximum						99 years
Amounts recognized in accumulated other comprehensive loss
Unrecognized actuarial loss (gain)		$ 105		$ 109		$ 105		$ 109
Unrecognized prior service cost		0		1		0		1
Deferred Tax Benefit On Accumulated Other Comprehensive Income		0		0		0		0
Net amount recognized in accumulated other comprehensive loss (gain)		105		110		105		110
Changes in plan assets and benefit obligations recognized in other comprehensive income
Net loss (gain)						4
Amortization of net loss						(8)
Prior service cost (2)						(1)
Total recognized in comprehensive income						(5)
Total expense recognized in net periodic cost and other comprehensive income						87
Pension benefits that have accumulated benefit obligations in excess of plan assets
Accumulated benefit obligation		2,352		1,930		2,352		1,930
Projected benefit obligation		2,385		1,952		2,385		1,952
Fair value of plan assets		2,005		1,516		2,005		1,516
Accumulated benefit obligation for all defined benefit pension plans		2,420		1,991		2,420		1,991
Non-qualified Pension Plan [Member]
Change in plan assets [Rollforward]
Employer contributions						23
Pension benefits that have accumulated benefit obligations in excess of plan assets
Accumulated benefit obligation		68		61		68		61
Projected benefit obligation		68		61		68		61
Fair value of plan assets		$ 0		$ 0		$ 0		$ 0
Minimum [Member] | Other Postretirement Benefits Plan [Member]
Amounts recognized in balance sheets
Health care cost trend rate assumed for the next year		5.50%		5.95%		5.50%		5.95%
Year that the cost trend rates reach the ultimate trend rate						2028		2026
Maximum [Member] | Other Postretirement Benefits Plan [Member]
Amounts recognized in balance sheets
Health care cost trend rate assumed for the next year		5.75%		28.60%		5.75%		28.60%
Year that the cost trend rates reach the ultimate trend rate						2029		2027
CERC Corp [Member]
Amounts recognized in balance sheets
Other liabilities-benefit obligations		$ (83)		$ (93)		$ (83)		$ (93)
Changes in plan assets and benefit obligations recognized in other comprehensive income
Amortization of net loss	[1]					0		0
Prior service cost (2)	[1]					0		(1)
CERC Corp [Member] | Other Postretirement Benefits Plan [Member]
Components of net periodic costs [Abstract]
Service cost (1)	[2]					1		1		$ 1
Interest cost (2)	[3]					5		4		5
Expected return on plan assets (2)	[3]					(1)		(1)		(1)
Amortization of prior service cost (2)	[3]					1		1		1
Net periodic cost (credit)						$ 6		$ 5		$ 6
Assumptions used to determine net periodic benefit (income) cost
Discount rate						3.20%		3.60%		4.15%
Expected return on plan assets		3.35%	[4]	4.15%	[4]	4.15%		3.85%		3.60%
Change in benefit obligation [Roll Forward]
Benefit obligation, beginning of year						$ 110		$ 109
Plan obligations assumed in Merger						0		0
Service cost (1)	[2]					1		1		$ 1
Interest cost (2)	[3]					5		4		5
Participant contributions						4		4
Benefits paid						(8)		(9)
Plan amendment						5		0
Actuarial (gain) loss (1)	[5]					(15)		(1)
Benefit obligation, end of year		$ 102		$ 110		102		110		109
Change in plan assets [Rollforward]
Fair value of plan assets, beginning of year						25		26
Employer contributions						3		4
Participant contributions						4		4
Benefits paid						(8)		(9)
Actual investment return						3		0
Fair value of plan assets, end of year		27		25		27		25		$ 26
Funded status of plan
Funded status, end of year		(75)		(85)		(75)		(85)
Amounts recognized in balance sheets
Current liabilities-other		(3)		(3)		(3)		(3)
Other liabilities-benefit obligations		(72)		(82)		(72)		(82)
Net liability, end of year		$ (75)		$ (85)		$ (75)		$ (85)
Discount rate (2)		3.25%	[6]	4.35%	[6]	3.25%	[6]	4.35%	[6]	3.60%
Expected return on plan assets (3)		3.35%	[4]	4.15%	[4]	4.15%		3.85%		3.60%
Prescription drug cost trend rate assumed for the next year - Pre-65						8.00%		9.20%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)		4.50%		4.50%		4.50%		4.50%
Annualized individual discount rates based on time period, minimum						6 months
Annualized individual discount rates based on time period, maximum						99 years
Amounts recognized in accumulated other comprehensive loss
Unrecognized actuarial loss (gain)		$ (12)		$ (3)		$ (12)		$ (3)
Unrecognized prior service cost		7		5		7		5
Deferred Tax Benefit On Accumulated Other Comprehensive Income		0		(9)		0		(9)
Net amount recognized in accumulated other comprehensive loss (gain)		$ (5)		$ (7)		(5)		$ (7)
Changes in plan assets and benefit obligations recognized in other comprehensive income
Net loss (gain)						(6)
Amortization of net loss						0
Prior service cost (2)						(1)
Total recognized in comprehensive income						(7)
Total expense recognized in net periodic cost and other comprehensive income						(1)
CERC Corp [Member] | Non-qualified Pension Plan [Member]
Change in plan assets [Rollforward]
Employer contributions						$ 0
CERC Corp [Member] | Minimum [Member] | Other Postretirement Benefits Plan [Member]
Amounts recognized in balance sheets
Health care cost trend rate assumed for the next year		5.50%		5.95%		5.50%		5.95%
Year that the cost trend rates reach the ultimate trend rate						2028		2026
CERC Corp [Member] | Maximum [Member] | Other Postretirement Benefits Plan [Member]
Amounts recognized in balance sheets
Health care cost trend rate assumed for the next year		5.75%		28.60%		5.75%		28.60%
Year that the cost trend rates reach the ultimate trend rate						2029		2027
Houston Electric [Member]
Amounts recognized in balance sheets
Other liabilities-benefit obligations		$ (75)		$ (91)		$ (75)		$ (91)
Changes in plan assets and benefit obligations recognized in other comprehensive income
Amortization of net loss	[1]					0		0
Prior service cost (2)	[1]					0		0
Houston Electric [Member] | Other Postretirement Benefits Plan [Member]
Components of net periodic costs [Abstract]
Service cost (1)	[2]					1		0		$ 1
Interest cost (2)	[3]					7		8		9
Expected return on plan assets (2)	[3]					(4)		(4)		(4)
Amortization of prior service cost (2)	[3]					(6)		(5)		(6)
Net periodic cost (credit)						$ (2)		$ (1)		$ 0
Assumptions used to determine net periodic benefit (income) cost
Discount rate						3.20%		3.60%		4.15%
Expected return on plan assets		4.05%	[4]	4.70%	[4]	4.70%		4.75%		4.75%
Change in benefit obligation [Roll Forward]
Benefit obligation, beginning of year						$ 166		$ 225
Plan obligations assumed in Merger						0		0
Service cost (1)	[2]					1		0		$ 1
Interest cost (2)	[3]					7		8		9
Participant contributions						2		2
Benefits paid						(13)		(13)
Plan amendment						3		0
Actuarial (gain) loss (1)	[5]					(4)		(56)
Benefit obligation, end of year		$ 162		$ 166		162		166		225
Change in plan assets [Rollforward]
Fair value of plan assets, beginning of year						89		93
Employer contributions						10		9
Participant contributions						2		2
Benefits paid						(13)		(13)
Actual investment return						13		(2)
Fair value of plan assets, end of year		101		89		101		89		$ 93
Funded status of plan
Funded status, end of year		(61)		(77)		(61)		(77)
Amounts recognized in balance sheets
Current liabilities-other		0		0		0		0
Other liabilities-benefit obligations		(61)		(77)		(61)		(77)
Net liability, end of year		$ (61)		$ (77)		$ (61)		$ (77)
Discount rate (2)		3.25%	[6]	4.35%	[6]	3.25%	[6]	4.35%	[6]	3.60%
Expected return on plan assets (3)		4.05%	[4]	4.70%	[4]	4.70%		4.75%		4.75%
Prescription drug cost trend rate assumed for the next year - Pre-65						8.00%		9.20%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)		4.50%		4.50%		4.50%		4.50%
Annualized individual discount rates based on time period, minimum						6 months
Annualized individual discount rates based on time period, maximum						99 years
Houston Electric [Member] | Non-qualified Pension Plan [Member]
Change in plan assets [Rollforward]
Employer contributions						$ 0
Houston Electric [Member] | Minimum [Member] | Other Postretirement Benefits Plan [Member]
Amounts recognized in balance sheets
Health care cost trend rate assumed for the next year		5.50%		5.95%		5.50%		5.95%
Year that the cost trend rates reach the ultimate trend rate						2028		2026
Houston Electric [Member] | Maximum [Member] | Other Postretirement Benefits Plan [Member]
Amounts recognized in balance sheets
Health care cost trend rate assumed for the next year		5.75%		28.60%		5.75%		28.60%
Year that the cost trend rates reach the ultimate trend rate						2029		2027
Operation And Maintenance Expense [Member] | Pension Plan [Member]
Components of net periodic costs [Abstract]
Service cost (1)	[10]					$ 40		$ 37		$ 36
Change in benefit obligation [Roll Forward]
Service cost (1)	[10]					40		37		36
Other Nonoperating Income (Expense) [Member] | Pension Plan [Member]
Components of net periodic costs [Abstract]
Interest cost (2)	[11]					96		79		89
Expected return on plan assets (2)	[11]					(105)		(107)		(97)
Amortization of prior service cost (2)	[11]					9		9		9
Amortization of net loss (2)	[11]					52		43		58
Settlement cost (2) (3)	[11]					2	[12]	0		0
Curtailment gain (2) (4)	[11]					(1)	[13]	0		0
Change in benefit obligation [Roll Forward]
Interest cost (2)	[11]					$ 96		$ 79		$ 89

[1] Amounts are included in the computation of net periodic cost and are reflected in Other, net in each of the Registrants’ respective Statements of Consolidated Income.

[2] Amounts presented in the table above are included in Operation and maintenance expense in each of the Registrants’ respective Statements of Consolidated Income, net of regulatory deferrals and amounts capitalized.

[3] Amounts presented in the table above are included in Other, net in each of the Registrants’ respective Statements of Consolidated Income, net of regulatory deferrals.

[4] The expected rate of return assumption was developed using the targeted asset allocation of the plans and the expected return for each asset class.

[5] Significant sources of gain for 2019 include favorable cost trend rates and benefit claims experience in addition to the change in mortality projection scale from MP2018 to MP2019. Significant sources of gain for 2018 include the increase in the discount rate from 3.60% to 4.35%, favorable benefit claims experience and cost trend rates in addition to the change in mortality projection scale from MP2017 to MP2018.

[6] The discount rate assumption was determined by matching the projected cash flows of the plans against a hypothetical yield curve of high-quality corporate bonds represented by a series of annualized individual discount rates from one-half to 99 years.

[7] The expected rate of return assumption was developed using the targeted asset allocation of CenterPoint Energy’s plans and the expected return for each asset class.

[8] Significant sources of loss for 2019 include the decrease in discount rate from 4.35% to 3.20%. Significant sources of gain for 2018 include the increase in discount rate from 3.65% to 4.35% and the mortality projection scale change from MP2017 to MP2018.

[9] The discount rate assumption was determined by matching the projected cash flows of CenterPoint Energy’s plans against a hypothetical yield curve of high-quality corporate bonds represented by a series of annualized individual discount rates from one-half to 99 years.

[10] Amounts presented in the table above are included in Operation and maintenance expense in CenterPoint Energy’s Statements of Consolidated Income, net of regulatory deferrals and amounts capitalized.

[11] Amounts presented in the table above are included in Other, net in CenterPoint Energy’s Statements of Consolidated Income, net of regulatory deferrals.

[12] A one-time, non-cash settlement cost is required when the total lump sum distributions or other settlements of plan benefit obligations during a plan year exceed the service cost and interest cost components of the net periodic cost for that year. In 2019, CenterPoint Energy recognized a non-cash settlement cost due to lump sum settlement payments.

[13] A curtailment gain or loss is required when the expected future services of a significant number of employees are reduced or eliminated for the accrual of benefits. In 2019, CenterPoint Energy recognized a pension curtailment gain related to employees who were terminated after the Merger closed.

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STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Net income	$ 791	$ 368	$ 1,792
Other comprehensive income (loss):
Adjustment to pension and other postretirement plans	12	(10)	6
Net deferred gain (loss) from cash flow hedges	(2)	(15)	(3)
Reclassification of deferred loss from cash flow hedges realized in net income (net of tax expense of $-0-, $-0- and $-0-, respectively)	1	0	0
Other comprehensive loss from unconsolidated affiliates, net of tax	(1)	0	0
Other comprehensive income (loss)	10	(25)	3
Comprehensive income	801	343	1,795
Preferred stock dividend requirement	117	35	0
Comprehensive income	684	308	1,795
Houston Electric [Member]
Net income	356	336	433
Other comprehensive income (loss):
Net deferred gain (loss) from cash flow hedges	(1)	(14)	(1)
Other comprehensive income (loss)	(1)	(14)	(1)
Comprehensive income	355	322	432
CERC Corp [Member]
Net income	212	208	745
Other comprehensive income (loss):
Adjustment to pension and other postretirement plans	5	1	4
Net deferred gain (loss) from cash flow hedges	0	(1)	(1)
Other comprehensive income (loss)	5	0	3
Comprehensive income	$ 217	$ 208	$ 748

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STATEMENTS OF CONSOLIDATED CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Cash Flows from Operating Activities:
Net income	$ 791	$ 368	$ 1,792
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	1,287	1,243	1,036
Amortization of deferred financing costs	29	48	24
Deferred income taxes	69	48	(770)
Goodwill impairment charge recorded from annual impairment test	48	0	0
Amortization expense of intangible assets recorded in Depreciation and amortization (1) (2)	24	0	0
Unrealized loss (gain) on marketable securities	(282)	22	(7)
Loss (gain) on indexed debt securities	292	232	(49)
Write-down of natural gas inventory	4	2	0
Income (Loss) from Equity Method Investments	(230)	(307)	(265)
Proceeds from Equity Method Investment, Distribution	261	267	0
Pension contributions	(109)	(69)	(48)
Changes in other assets and liabilities, excluding acquisitions:
Accounts receivable and unbilled revenues, net	226	(154)	(216)
Inventory	(52)	1	(7)
Taxes receivable	(106)	0	30
Accounts payable	(455)	220	136
Fuel cost recovery	92	33	(85)
Non-trading derivatives, net	(64)	103	(84)
Margin deposits, net	(56)	5	(55)
Interest and taxes accrued	54	40	5
Net regulatory assets and liabilities	(114)	28	(107)
Other current assets	(22)	0	(3)
Other current liabilities	(107)	(24)	34
Other assets	103	6	(4)
Other liabilities	(54)	12	36
Other, net	9	12	24
Net cash provided by operating activities	1,638	2,136	1,417
Cash Flows from Investing Activities:
Capital expenditures	(2,506)	(1,651)	(1,426)
Acquisitions, net of cash acquired	(5,991)	0	(132)
Distributions from unconsolidated affiliates in excess of cumulative earnings	42	30	297
Proceeds from sale of marketable securities	0	398	0
Proceeds from sale of assets	5	0	0
Purchase of investments	(6)	0	0
Other, net	35	16	4
Net cash provided by (used in) investing activities	(8,421)	(1,207)	(1,257)
Cash Flows from Financing Activities:
Increase (decrease) in short-term borrowings, net	0	(39)	4
Proceeds from (payments of) commercial paper, net	1,891	(1,543)	349
Proceeds from long-term debt, net	2,916	2,495	1,096
Payments of long-term debt	(1,302)	(484)	(1,211)
Loss on reacquired debt	0	0	(5)
Debt and equity issuance costs	(20)	(47)	(13)
Payment of dividends on Common Stock	(577)	(499)	(461)
Payment of dividends on preferred stock	(118)	(11)	0
Proceeds from issuance of Common Stock, net	0	1,844	0
Proceeds from issuance of preferred stock, net	0	1,740	0
Distribution to ZENS holders	0	(398)	0
Other, net	(14)	(5)	(4)
Net cash provided by (used in) financing activities	2,776	3,053	(245)
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	(4,007)	3,982	(85)
Cash, Cash Equivalents and Restricted Cash at Beginning of Year	4,278	296	381
Cash, Cash Equivalents and Restricted Cash at End of Year	271	4,278	296
Houston Electric [Member]
Cash Flows from Operating Activities:
Net income	356	336	433
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	648	917	724
Amortization of deferred financing costs	12	11	13
Deferred income taxes	(24)	(38)	(98)
Changes in other assets and liabilities, excluding acquisitions:
Accounts receivable and unbilled revenues, net	38	11	(73)
Accounts receivable/payable–affiliated companies	(23)	20	(46)
Inventory	(12)	(16)	15
Taxes receivable	5	(5)	6
Accounts payable	13	(1)	59
Non-trading derivatives, net	(25)	5	0
Interest and taxes accrued	13	(2)	7
Net regulatory assets and liabilities	(48)	(97)	(148)
Other current assets	(5)	(2)	(6)
Other current liabilities	(9)	(26)	16
Other assets	5	(3)	13
Other liabilities	(12)	17	(4)
Other, net	(14)	(12)	(6)
Net cash provided by operating activities	918	1,115	905
Cash Flows from Investing Activities:
Capital expenditures	(1,025)	(922)	(875)
(Increase) decrease in notes receivable–affiliated companies	(481)	0	96
Other, net	11	11	3
Net cash provided by (used in) investing activities	(1,495)	(911)	(776)
Cash Flows from Financing Activities:
Proceeds from long-term debt, net	696	398	298
Payments of long-term debt	(458)	(434)	(411)
Dividend to parent	(376)	(209)	(180)
Increase (decrease) in notes payable–affiliated companies	(1)	(59)	60
Debt issuance costs	(8)	(4)	(3)
Contribution from parent	590	200	0
Other, net	(1)	0	0
Net cash provided by (used in) financing activities	442	(108)	(236)
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	(135)	96	(107)
Cash, Cash Equivalents and Restricted Cash at Beginning of Year	370	274	381
Cash, Cash Equivalents and Restricted Cash at End of Year	235	370	274
CERC Corp [Member]
Cash Flows from Operating Activities:
Net income	212	208	745
Income (loss) from discontinued operations, net of tax	0	138	161
Income (loss) from continuing operations	212	70	584
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	305	293	279
Amortization of deferred financing costs	9	9	9
Deferred income taxes	7	31	(224)
Goodwill impairment charge recorded from annual impairment test	48	0	0
Write-down of natural gas inventory	4	2	0
Changes in other assets and liabilities, excluding acquisitions:
Accounts receivable and unbilled revenues, net	252	(155)	(143)
Accounts receivable/payable–affiliated companies	(6)	9	0
Inventory	(12)	17	(22)
Accounts payable	(305)	163	64
Fuel cost recovery	86	33	(85)
Non-trading derivatives, net	(60)	98	(82)
Margin deposits, net	(56)	5	(55)
Interest and taxes accrued	2	0	(41)
Net regulatory assets and liabilities	(10)	50	(27)
Other current assets	1	4	2
Other current liabilities	22	(3)	15
Other assets	5	5	(8)
Other liabilities	(38)	6	6
Other, net	0	1	6
Net cash provided by operating activities from continuing operations	466	638	278
Net cash provided by operating activities from discontinued operations	0	176	0
Net cash provided by operating activities	466	814	278
Cash Flows from Investing Activities:
Capital expenditures	(776)	(633)	(513)
Acquisitions, net of cash acquired	0	0	(132)
(Increase) decrease in notes receivable–affiliated companies	114	(114)	0
Other, net	0	3	2
Net cash used in investing activities from continuing operations	(662)	(744)	(643)
Net cash provided by investing activities from discontinued operations	0	47	297
Net cash provided by (used in) investing activities	(662)	(697)	(346)
Cash Flows from Financing Activities:
Increase (decrease) in short-term borrowings, net	0	(39)	4
Proceeds from (payments of) commercial paper, net	167	(688)	329
Proceeds from long-term debt, net	0	599	298
Payments of long-term debt	0	0	(550)
Dividend to parent	(120)	(360)	(601)
Increase (decrease) in notes payable–affiliated companies	0	(570)	570
Loss on reacquired debt	0	0	(5)
Debt issuance costs	0	(5)	(4)
Contribution from parent	129	960	38
Other, net	(3)	(1)	0
Net cash used in financing activities from continuing operations	173	(104)	79
Net cash provided by financing activities from discontinued operations	0	0	0
Net cash provided by (used in) financing activities	173	(104)	79
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	(23)	13	11
Cash, Cash Equivalents and Restricted Cash at Beginning of Year	25	12	1
Cash, Cash Equivalents and Restricted Cash at End of Year	$ 2	$ 25	$ 12

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Goodwill and Other Intangibles (CenterPoint Energy and CERC) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019		Dec. 31, 2018	Dec. 31, 2017
Goodwill [Line Items]
Goodwill		$ 5,164		$ 867
Goodwill, Acquired During Period		0
Goodwill impairment charge recorded from annual impairment test		48		0	$ 0
Finite-Lived Intangible Assets, Net [Abstract]
Gross Carrying Amount		411		106
Accumulated Amortization		(90)		(41)
Net Balance		321		65
Amortization expense of intangible assets recorded in Depreciation and amortization (1) (2)		24		0	0
2020		29
2021		25
2022		25
2023		24
2024		22
Deferred Tax Liabilities, Net, Noncurrent		3,928		3,239
Customer Relationships [Member]
Finite-Lived Intangible Assets, Net [Abstract]
Gross Carrying Amount		286	[1]	86
Accumulated Amortization		(43)	[1]	(27)
Net Balance		243	[1]	59
Covenants Not To Compete [Member]
Finite-Lived Intangible Assets, Net [Abstract]
Gross Carrying Amount		4		4
Accumulated Amortization		(4)		(3)
Net Balance		0		1
Trade Names [Member]
Finite-Lived Intangible Assets, Net [Abstract]
Gross Carrying Amount		58	[1]	0
Accumulated Amortization		(5)	[1]	0
Net Balance		53	[1]	0
Construction backlog [Member]
Finite-Lived Intangible Assets, Net [Abstract]
Gross Carrying Amount		27	[1],[2]	0
Accumulated Amortization		(23)	[1],[2]	0
Net Balance		4	[1],[2]	0
Operation and maintenance agreements [Member]
Finite-Lived Intangible Assets, Net [Abstract]
Gross Carrying Amount		12	[1],[2]	0
Accumulated Amortization		(1)	[1],[2]	0
Net Balance		11	[1],[2]	0
Other [Member]
Finite-Lived Intangible Assets, Net [Abstract]
Gross Carrying Amount		24	[1]	16
Accumulated Amortization		(14)	[1]	(11)
Net Balance		10	[1]	5
Indiana Electric Integrated [Member]
Goodwill [Line Items]
Goodwill		1,121		0
Goodwill, Acquired During Period	[3]	1,121
Goodwill impairment charge recorded from annual impairment test		0
Natural Gas Distribution [Member]
Goodwill [Line Items]
Goodwill		3,312		746
Goodwill, Acquired During Period	[3]	2,566
Goodwill impairment charge recorded from annual impairment test		0
Energy Services [Member]
Goodwill [Line Items]
Goodwill	[4]	62		110
Goodwill impairment charge recorded from annual impairment test		48
Accumulated goodwill impairment charge recorded in 2012		252
Finite-Lived Intangible Assets, Net [Abstract]
Deferred Tax Liabilities, Net, Noncurrent		25
Goodwill, Impairment Loss, Net of Tax		45
Infrastructure Services [Member]
Goodwill [Line Items]
Goodwill		220		0
Goodwill, Acquired During Period	[3]	220
Goodwill impairment charge recorded from annual impairment test		0
Finite-Lived Intangible Assets, Net [Abstract]
Deferred Tax Liabilities, Net, Noncurrent		123
Corporate and Other [Member]
Goodwill [Line Items]
Goodwill		449		11
Goodwill, Acquired During Period	[3]	438
Goodwill impairment charge recorded from annual impairment test		0
Vectren acquisition [Member]
Goodwill [Line Items]
Goodwill, Acquired During Period	[3]	4,345
CERC Corp [Member]
Goodwill [Line Items]
Goodwill		819		867
Goodwill impairment charge recorded from annual impairment test		48		0	0
Finite-Lived Intangible Assets, Net [Abstract]
Gross Carrying Amount		106		106
Accumulated Amortization		(50)		(41)
Net Balance		56		65
2020		6
2021		6
2022		6
2023		5
2024		5
Deferred Tax Liabilities, Net, Noncurrent		470		406
CERC Corp [Member] | Customer Relationships [Member]
Finite-Lived Intangible Assets, Net [Abstract]
Gross Carrying Amount		86		86
Accumulated Amortization		(32)		(27)
Net Balance		54		59
CERC Corp [Member] | Covenants Not To Compete [Member]
Finite-Lived Intangible Assets, Net [Abstract]
Gross Carrying Amount		4		4
Accumulated Amortization		(4)		(3)
Net Balance		0		1
CERC Corp [Member] | Other [Member]
Finite-Lived Intangible Assets, Net [Abstract]
Gross Carrying Amount		16		16
Accumulated Amortization		(14)		(11)
Net Balance		2		5
CERC Corp [Member] | Natural Gas Distribution [Member]
Goodwill [Line Items]
Goodwill		746		746
Goodwill impairment charge recorded from annual impairment test		0
CERC Corp [Member] | Energy Services [Member]
Goodwill [Line Items]
Goodwill	[5]	62		110
Goodwill impairment charge recorded from annual impairment test		48
Accumulated goodwill impairment charge recorded in 2012		252
Finite-Lived Intangible Assets, Net [Abstract]
Deferred Tax Liabilities, Net, Noncurrent		25
Goodwill, Impairment Loss, Net of Tax		48
CERC Corp [Member] | Corporate and Other [Member]
Goodwill [Line Items]
Goodwill		11		11
Goodwill impairment charge recorded from annual impairment test		0
Depreciation and amortization expense [Member]
Finite-Lived Intangible Assets, Net [Abstract]
Amortization expense of intangible assets recorded in Depreciation and amortization (1) (2)		25	[6],[7]	10	13
Depreciation and amortization expense [Member] | CERC Corp [Member]
Finite-Lived Intangible Assets, Net [Abstract]
Amortization expense of intangible assets recorded in Depreciation and amortization (1) (2)		9		10	13
Non-utility cost of revenues [Member]
Finite-Lived Intangible Assets, Net [Abstract]
Amortization expense of intangible assets recorded in Depreciation and amortization (1) (2)		24	[7]	$ 0	$ 0
Vectren [Member]
Goodwill [Line Items]
Goodwill		4,339
Vectren [Member] | Depreciation and amortization expense [Member]
Finite-Lived Intangible Assets, Net [Abstract]
Amortization expense of intangible assets recorded in Depreciation and amortization (1) (2)		$ 17

[1] The fair value of intangible assets acquired through acquisitions has been finalized. See Note 4.

[2] Amortization expense related to the operation and maintenance agreements and construction backlog is included in Non-utility cost of revenues, including natural gas on CenterPoint Energy’s Statements of Consolidated Income.

[3] This represents the allocation of goodwill to reportable segments from the Merger, changes from preliminary amounts previously reported and includes the final determination of fair value for each reportable segment. See Note 4.

[4] Amount presented is net of the accumulated goodwill impairment charge of $252 million recorded in 2012. As of December 31, 2019, CenterPoint Energy and CERC identified a triggering event to perform an interim goodwill impairment test and recognized a goodwill impairment on their Energy Services reporting unit which is included in Goodwill impairment on CenterPoint Energy’s and CERC’s Consolidated Statements of Income.

[5] Amount presented is net of the accumulated goodwill impairment charge of $252 million recorded in 2012.

[6] Includes $17 million for the year ended December 31, 2019 of amortization expense related to intangibles acquired in the Merger.

[7] The fair value of intangible assets, and related amortization assumptions, acquired through acquisitions during the year ended December 31, 2019, has been finalized. See Note 4.

XML

Mergers and Acquisitions (Details) - USD ($) $ / shares in Units, $ in Millions		3 Months Ended								12 Months Ended
	Feb. 01, 2019	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019		Dec. 31, 2018		Dec. 31, 2017
Dividends declared per share										$ 0.86		$ 1.1200		$ 1.35
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net [Abstract]
Goodwill		$ 5,164				$ 867				$ 5,164		$ 867
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Intangible Assets, Other than Goodwill [Abstract]
Amortization expense of intangible assets										24		0		$ 0
Business Combination, Separately recognized Transactions, Additional Disclosures [Abstract]
Total revenues		$ 3,230	$ 2,742	$ 2,798	$ 3,531	$ 3,036	$ 2,212	$ 2,186	$ 3,155	12,301		10,589		9,614
Net income										791		368		1,792
Non-utility cost of revenues [Member]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Intangible Assets, Other than Goodwill [Abstract]
Amortization expense of intangible assets										24	[1]	0		0
Depreciation and amortization expense [Member]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Intangible Assets, Other than Goodwill [Abstract]
Amortization expense of intangible assets										25	[1],[2]	10		$ 13
Vectren [Member]
Total purchase price consideration	$ 6,000									$ 5,982
Cash paid per share of Vectren common stock at closing of the Merger		$ 72.00								$ 72.00
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net [Abstract]
Cash and cash equivalents		$ 16								$ 16
Other current assets		577								577
Property, plant and equipment, net		5,147								5,147
Identifiable intangibles		297								297
Regulatory assets		338								338
Other assets		141								141
Total assets acquired		6,516								6,516
Current liabilities		648								648
Regulatory liabilities		938								938
Other liabilities		886								886
Long-term debt		2,401								2,401
Total liabilities assumed		4,873								4,873
Net assets acquired		1,643								1,643
Goodwill		4,339								4,339
Total purchase price consideration	$ 6,000									5,982
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Intangible Assets, Other than Goodwill [Abstract]
Estimated Fair Value										297
Business Combination, Separately recognized Transactions, Additional Disclosures [Abstract]
Total revenues										2,729
Net income										190
Business Acquisition, Pro Forma Information [Abstract]
Operating Revenue										12,547		13,282
Net Income (1)										812	[3]	458	[4]
Vectren [Member] | Operation And Maintenance Expense [Member]
Severance expense related to the Merger					$ 61					102
Business Combination, Separately recognized Transactions, Additional Disclosures [Abstract]
Integration costs										83
Vectren [Member] | Depreciation and amortization expense [Member]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Intangible Assets, Other than Goodwill [Abstract]
Amortization expense of intangible assets										$ 17
Vectren [Member] | Operation and maintenance agreements [Member]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Intangible Assets, Other than Goodwill [Abstract]
Weighted Average Useful Lives										24 years
Estimated Fair Value										$ 12
Vectren [Member] | Customer Relationships [Member]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Intangible Assets, Other than Goodwill [Abstract]
Weighted Average Useful Lives										18 years
Estimated Fair Value										$ 200
Vectren [Member] | Construction backlog [Member]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Intangible Assets, Other than Goodwill [Abstract]
Weighted Average Useful Lives										1 year
Estimated Fair Value										$ 27
Vectren [Member] | Trade Names [Member]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Intangible Assets, Other than Goodwill [Abstract]
Weighted Average Useful Lives										10 years
Estimated Fair Value										$ 58
Vectren [Member] | Operation and maintenance agreements and construction backlog [Member] | Non-utility cost of revenues [Member]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Intangible Assets, Other than Goodwill [Abstract]
Amortization expense of intangible assets										24
Vectren [Member] | Customer relationships and trade names [Member] | Depreciation and amortization expense [Member]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Intangible Assets, Other than Goodwill [Abstract]
Amortization expense of intangible assets										$ 16
Vectren [Member] | Stub period [Member]
Dividends declared per share										$ 0.41145
Vectren acquisition [Member]
Cash payments towards outstanding share-based awards		78								$ 78
Share-based award liability recorded		41								41
Incremental share-based awards expense recorded										37
Utility pipeline construction company [Member]
Total purchase price consideration										25
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net [Abstract]
Identifiable intangibles		8								8
Goodwill		$ 6								6
Total purchase price consideration										25
Vectren [Member] | Pro Forma [Member] | Vectren acquisition [Member]
Business Acquisition, Pro Forma Information [Abstract]
Transaction costs associated with the Merger										$ 37		$ 37

[1] The fair value of intangible assets, and related amortization assumptions, acquired through acquisitions during the year ended December 31, 2019, has been finalized. See Note 4.

[2] Includes $17 million for the year ended December 31, 2019 of amortization expense related to intangibles acquired in the Merger.

[3] Pro forma net income was adjusted to exclude $37 million of Vectren Merger-related transaction costs incurred in 2019.

[4] Pro forma net income was adjusted to include $37 million of Vectren Merger-related transaction costs incurred in 2019.

XML

Subsequent Events (Details) - USD ($) $ / shares in Units, $ in Millions																12 Months Ended
	Feb. 24, 2020	Feb. 07, 2020	Feb. 03, 2020	Oct. 17, 2019	Jul. 31, 2019	Apr. 25, 2019	Dec. 12, 2018	Oct. 23, 2018	Jul. 26, 2018	Apr. 26, 2018	Dec. 13, 2017	Oct. 25, 2017	Jul. 27, 2017	Apr. 27, 2017	Jan. 05, 2017	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Subsequent Event [Line Items]
Deferred Tax Liabilities, Net, Noncurrent																$ 3,928	$ 3,239
Common stock dividends declared per share																$ 0.86	$ 1.1200	$ 1.35
Expected cash distribution on Enable Common Units																$ 261	$ 267	$ 0
Series A Preferred Units [Member] | Subsequent Event [Member] | Enable Midstream Partners [Member]
Subsequent Event [Line Items]
Declaration Date		Feb. 07, 2020
Record Date		Feb. 07, 2020
Payment Date		Feb. 14, 2020
Distributions Declared, Per Unit		$ 0.6250
Expected cash distribution on Enable's Series A Preferred Units		$ 9
Common Units [Member] | Subsequent Event [Member] | Enable Midstream Partners [Member]
Subsequent Event [Line Items]
Declaration Date		Feb. 07, 2020
Record Date		Feb. 18, 2020
Payment Date		Feb. 25, 2020
Distributions Declared, Per Unit		$ 0.3305
Expected cash distribution on Enable Common Units		$ 77
Common Stock [Member]
Subsequent Event [Line Items]
Declaration Date				Oct. 17, 2019	Jul. 31, 2019	Apr. 25, 2019	Dec. 12, 2018	Oct. 23, 2018	Jul. 26, 2018	Apr. 26, 2018	Dec. 13, 2017	Oct. 25, 2017	Jul. 27, 2017	Apr. 27, 2017	Jan. 05, 2017
Record Date				Nov. 21, 2019	Aug. 15, 2019	May 16, 2019	Feb. 21, 2019	Nov. 15, 2018	Aug. 16, 2018	May 17, 2018	Feb. 15, 2018	Nov. 16, 2017	Aug. 16, 2017	May 16, 2017	Feb. 16, 2017
Payment Date				Dec. 12, 2019	Sep. 12, 2019	Jun. 13, 2019	Mar. 14, 2019	Dec. 13, 2018	Sep. 13, 2018	Jun. 14, 2018	Mar. 08, 2018	Dec. 08, 2017	Sep. 08, 2017	Jun. 09, 2017	Mar. 10, 2017
Common stock dividends declared per share				$ 0.2875	$ 0.2875	$ 0.2875	$ 0.2875	$ 0.2775	$ 0.2775	$ 0.2775	$ 0.2775	$ 0.2675	$ 0.2675	$ 0.2675	$ 0.2675	$ 0.8625	$ 1.1200	$ 1.3475
Common Stock [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Declaration Date			Feb. 03, 2020
Record Date			Feb. 20, 2020
Payment Date			Mar. 12, 2020
Common stock dividends declared per share			$ 0.2900
Series A Preferred Stock [Member]
Subsequent Event [Line Items]
Declaration Date					Jul. 31, 2019		Dec. 12, 2018
Record Date					Aug. 15, 2019		Feb. 15, 2019
Payment Date					Sep. 03, 2019		Mar. 01, 2019
Preferred stock dividends declared per share					$ 30.6250		$ 32.1563									30.6250	32.1563	0.0000
Series A Preferred Stock [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Declaration Date			Feb. 03, 2020
Record Date			Feb. 14, 2020
Payment Date			Mar. 02, 2020
Preferred stock dividends declared per share			$ 30.6250
Series B Preferred Stock [Member]
Subsequent Event [Line Items]
Declaration Date				Oct. 17, 2019	Jul. 31, 2019	Apr. 25, 2019	Dec. 12, 2018	Oct. 23, 2018
Record Date				Nov. 15, 2019	Aug. 15, 2019	May 15, 2019	Feb. 15, 2019	Nov. 15, 2018
Payment Date				Dec. 02, 2019	Sep. 03, 2019	Jun. 03, 2019	Mar. 01, 2019	Dec. 01, 2018
Preferred stock dividends declared per share				$ 17.5000	$ 17.5000	$ 17.5000	$ 17.5000	$ 11.6667								$ 52.5000	$ 29.1667	$ 0.0000
Series B Preferred Stock [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Declaration Date			Feb. 03, 2020
Record Date			Feb. 14, 2020
Payment Date			Mar. 02, 2020
Preferred stock dividends declared per share			$ 17.5000
Infrastructure Services [Member]
Subsequent Event [Line Items]
Deferred Tax Liabilities, Net, Noncurrent																$ 123
Infrastructure Services [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Sales price of outstanding equity interests			$ 850
Energy Services [Member]
Subsequent Event [Line Items]
Deferred Tax Liabilities, Net, Noncurrent																25
Energy Services [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Sales price of outstanding equity interests	$ 400
CERC Corp [Member]
Subsequent Event [Line Items]
Deferred Tax Liabilities, Net, Noncurrent																470	$ 406
CERC Corp [Member] | Energy Services [Member]
Subsequent Event [Line Items]
Deferred Tax Liabilities, Net, Noncurrent																$ 25
CERC Corp [Member] | Energy Services [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Sales price of outstanding equity interests	$ 400

XML

Earnings Per Share (CenterPoint Energy)

12 Months Ended

Dec. 31, 2019

Earnings Per Share [Abstract]

Earnings Per Share (CenterPoint Energy) [Text Block]

Earnings Per Share (CenterPoint Energy)

The following table reconciles numerators and denominators of CenterPoint Energy’s basic and diluted earnings per common share. Basic earnings per common share is determined by dividing Income available to common shareholders - basic by the Weighted average common shares outstanding - basic for the applicable period. Diluted earnings per common share is determined by the inclusion of potentially dilutive common stock equivalent shares that may occur if securities to issue Common Stock were exercised or converted into Common Stock.

	For the Year Ended December 31,
	2019		2018		2017
	(in millions, except per share and share amounts)
Numerator:
Income available to common shareholders - basic (1)	$	674	$	333	$	1,792
Add back: Series B Preferred Stock dividend (2)	—		—		—
Income available to common shareholders - diluted (1)	$	674	$	333	$	1,792
Denominator:
Weighted average common shares outstanding - basic	502,050,000		448,829,000		430,964,000
Plus: Incremental shares from assumed conversions:
Restricted stock (3)	3,107,000		3,636,000		3,344,000
Series B Preferred Stock (2)	—		—		—
Weighted average common shares outstanding - diluted	505,157,000		452,465,000		434,308,000
Earnings per common share:
Basic earnings per common share	$	1.34	$	0.74	$	4.16
Diluted earnings per common share	$	1.33	$	0.74	$	4.13

(1) Income available to common shareholders for the year ended December 31, 2019 includes net income from businesses acquired in the Merger of $190 million. See Note 4. Income available to common shareholders for the year ended December 31, 2017 includes a reduction in income tax expense of $1,113 million due to tax reform. See Note 15 for further discussion of the impacts of the TCJA.

(2) The potentially dilutive impact from Series B Preferred Stock applies the if-converted method in calculating diluted earnings per common share. Under this method, diluted earnings per common share is adjusted for the more dilutive effect of the Series B Preferred Stock as a result of either its accumulated dividend for the period in the numerator or the assumed-converted common share equivalent in the denominator. The computation of diluted earnings per common share outstanding for the year ended December 31, 2019 and December 31, 2018 excludes Series B Stock Dividends of $68 million and $17 million, respectively, and 34,354,000 and 8,885,000 potentially dilutive shares, respectively, because to include them would be anti-dilutive. However, these shares could be potentially dilutive in the future.

(3)

The potentially dilutive impact from restricted stock awards applies the treasury stock method. Under this method, an increase in the average fair market value of Common Stock can result in a greater dilutive impact from these securities.

XML

Equity (CenterPoint Energy)

12 Months Ended

Dec. 31, 2019

Stockholders' Equity Note [Abstract]

Equity (CenterPoint Energy) [Text Block]

Equity (CenterPoint Energy)

Dividends Declared and Paid (CenterPoint Energy)

CenterPoint Energy declared dividends on its Common Stock during 2019, 2018 and 2017 as presented in the table below:

Declaration Date	Record Date	Payment Date	Per Share		Total (in millions)
October 17, 2019	November 21, 2019	December 12, 2019	$	0.2875	$	144
July 31, 2019	August 15, 2019	September 12, 2019	0.2875		145
April 25, 2019	May 16, 2019	June 13, 2019	0.2875		144
Total 2019			$	0.8625	$	433
December 12, 2018	February 21, 2019	March 14, 2019	$	0.2875	$	144
October 23, 2018	November 15, 2018	December 13, 2018	0.2775		139
July 26, 2018	August 16, 2018	September 13, 2018	0.2775		120
April 26, 2018	May 17, 2018	June 14, 2018	0.2775		120
Total 2018			$	1.1200	$	523

Declaration Date	Record Date	Payment Date	Per Share		Total (in millions)
December 13, 2017	February 15, 2018	March 8, 2018	$	0.2775	$	120
October 25, 2017	November 16, 2017	December 8, 2017	0.2675		116
July 27, 2017	August 16, 2017	September 8, 2017	0.2675		115
April 27, 2017	May 16, 2017	June 9, 2017	0.2675		115
January 5, 2017	February 16, 2017	March 10, 2017	0.2675		115
Total 2017			$	1.3475	$	581

CenterPoint Energy declared dividends on its Series A Preferred Stock during 2019 and 2018 as presented in the table below:

Declaration Date	Record Date	Payment Date	Per Share		Total (in millions)
July 31, 2019	August 15, 2019	September 3, 2019	$	30.6250	$	24
Total 2019			$	30.6250	$	24
December 12, 2018	February 15, 2019	March 1, 2019	$	32.1563	$	26
Total 2018			$	32.1563	$	26

CenterPoint Energy declared dividends on its Series B Preferred Stock during 2019 and 2018 as presented in the table below:

Declaration Date	Record Date	Payment Date	Per Share		Total (in millions)
October 17, 2019	November 15, 2019	December 2, 2019	$	17.5000	$	17
July 31, 2019	August 15, 2019	September 3, 2019	17.5000		17
April 25, 2019	May 15, 2019	June 3, 2019	17.5000		17
Total 2019			$	52.5000	$	51
December 12, 2018	February 15, 2019	March 1, 2019	$	17.5000	$	17
October 23, 2018	November 15, 2018	December 1, 2018	11.6667		11
Total 2018			$	29.1667	$	28

There were no Series A Preferred Stock or Series B Preferred Stock outstanding or dividends declared in 2017.

Dividend Requirement on Preferred Stock

	Year Ended December 31,
	2019		2018		2017
	(in millions)
Series A Preferred Stock	$	49	$	18	$	—
Series B Preferred Stock	68		17		—
Total preferred stock dividend requirement	$	117	$	35	$	—

Series A Preferred Stock

On August 22, 2018, CenterPoint Energy completed the issuance of 800,000 shares of its Series A Preferred Stock, at a price of $1,000 per share, resulting in net proceeds of $790 million after issuance costs. The aggregate liquidation value of the Series A Preferred Stock is $800 million with a per share liquidation value of $1,000.

CenterPoint Energy used the net proceeds from the Series A Preferred Stock offering to fund a portion of the Merger and to pay related fees and expenses.

Dividends. The Series A Preferred Stock accrue cumulative dividends, calculated as a percentage of the stated amount per share, at a fixed annual rate of 6.125% per annum to, but excluding, September 1, 2023, and at an annual rate of three-month LIBOR plus a spread of 3.270% thereafter to be paid in cash if, when and as declared. If declared, prior to September 1, 2023, dividends are payable semi-annually in arrears on each March 1 and September 1, beginning on March 1, 2019, and, for the period commencing on September 1, 2023, dividends are payable quarterly in arrears each March 1, June 1, September 1 and December 1, beginning on December 1, 2023. Cumulative dividends earned during the applicable periods are presented on CenterPoint Energy’s Statements of Consolidated Income as Preferred stock dividend requirement.

Optional Redemption. On or after September 1, 2023, CenterPoint Energy may, at its option, redeem the Series A Preferred Stock, in whole or in part, at any time or from time to time, for cash at a redemption price of $1,000 per share, plus any accumulated and unpaid dividends thereon to, but excluding, the redemption date.

At any time within 120 days after the conclusion of any review or appeal process instituted by CenterPoint Energy, if any, following the occurrence of a ratings event, CenterPoint Energy may, at its option, redeem the Series A Preferred Stock in whole, but not in part, at a redemption price in cash per share equal to $1,020 (102% of the liquidation value of $1,000) plus an amount equal to all accumulated and unpaid dividends thereon to, but excluding, the redemption date, whether or not declared.

Ranking. The Series A Preferred Stock, with respect to anticipated dividends and distributions upon CenterPoint Energy’s liquidation or dissolution, or winding-up of CenterPoint Energy’s affairs, ranks or will rank:

• senior to Common Stock and to each other class or series of capital stock established after the initial issue date of the Series A Preferred Stock that is expressly made subordinated to the Series A Preferred Stock;

• on a parity with any class or series of capital stock established after the initial issue date of the Series A Preferred Stock that is not expressly made senior or subordinated to the Series A Preferred Stock, including the Series B Preferred Stock;

• junior to any class or series of capital stock established after the initial issue date of the Series A Preferred Stock that is expressly made senior to the Series A Preferred Stock;

• junior to all existing and future indebtedness (including indebtedness outstanding under CenterPoint Energy’s credit facilities, senior notes and commercial paper) and other liabilities with respect to assets available to satisfy claims against CenterPoint Energy; and

• structurally subordinated to any existing and future indebtedness and other liabilities of CenterPoint Energy’s subsidiaries and capital stock of CenterPoint Energy’s subsidiaries held by third parties.

Voting Rights. Holders of the Series A Preferred Stock generally will not have voting rights. Whenever dividends on shares of Series A Preferred Stock have not been declared and paid for the equivalent of three or more semi-annual or six or more quarterly dividend periods (including, for the avoidance of doubt, the dividend period beginning on, and including, the original issue date and ending on, but excluding, March 1, 2019), whether or not consecutive, the holders of such shares of Series A Preferred Stock, voting together as a single class with holders of any and all other series of voting preferred stock (as defined in the Statement of Resolution for the Series A Preferred Stock) then outstanding, will be entitled at CenterPoint Energy’s next annual or special meeting of shareholders to vote for the election of a total of two additional members of CenterPoint Energy’s Board of Directors, subject to certain limitations. This right will terminate if and when all accumulated dividends have been paid in full and, upon such termination, the term of office of each director so elected will terminate at such time and the number of directors on CenterPoint Energy’s Board of Directors will automatically decrease by two, subject to the revesting of such rights in the event of each subsequent nonpayment.

Series B Preferred Stock

On October 1, 2018, CenterPoint Energy completed the issuance of 19,550,000 depositary shares, each representing a 1/20th interest in a share of its Series B Preferred Stock, at a price of $50 per depositary share, resulting in net proceeds of $950 million after issuance costs. The aggregate liquidation value of Series B Preferred Stock is $978 million with a per share liquidation value of $1,000. The amount issued included 2,550,000 depositary shares issued pursuant to the exercise in full of the option granted to the underwriters to purchase additional depositary shares.

CenterPoint Energy used the net proceeds from the offering of depositary shares, each representing a 1/20th interest in a share of its Series B Preferred Stock, to fund a portion of the Merger and to pay related fees and expenses.

Dividends. Dividends on the Series B Preferred Stock will be payable on a cumulative basis when, as and if declared at an annual rate of 7.00% on the liquidation value of $1,000 per share. CenterPoint Energy may pay declared dividends in cash or, subject to certain limitations, in shares of Common Stock, or in any combination of cash and shares of Common Stock on March 1, June 1, September 1 and December 1 of each year, commencing on December 1, 2018 and ending on, and including, September 1, 2021. Cumulative dividends earned during the applicable periods are presented on CenterPoint Energy’s Statements of Consolidated Income as Preferred stock dividend requirement.

Mandatory Conversion. Unless earlier converted or redeemed, each share of the Series B Preferred Stock will automatically convert on the mandatory conversion date, which is expected to be September 1, 2021, into not less than 30.5820 and not more than 36.6980 shares of Common Stock, subject to certain anti-dilution adjustments. Correspondingly, the conversion rate per depositary share will be not less than 1.5291 and not more than 1.8349 shares of Common Stock, subject to certain anti-dilution adjustments. The conversion rate will be determined based on a preceding 20-day volume-weighted-average-price of Common Stock.

The following table illustrates the conversion rate per share of the Series B Preferred Stock, subject to certain anti-dilution adjustments:

Applicable Market Value of the Common Stock	Conversion Rate per Share of Series B Preferred Stock
Greater than $32.6990 (threshold appreciation price)	30.5820 shares of Common Stock
Equal to or less than $32.6990 but greater than or equal to $27.2494	Between 30.5820 and 36.6980 shares of Common Stock, determined by dividing $1,000 by the applicable market value
Less than $27.2494 (initial price)	36.6980 shares of Common Stock

The following table illustrates the conversion rate per depositary share, subject to certain anti-dilution adjustments:

Applicable Market Value of the Common Stock	Conversion Rate per Depository Share
Greater than $32.6990 (threshold appreciation price)	1.5291 shares of Common Stock
Equal to or less than $32.6990 but greater than or equal to $27.2494	Between 1.5291 and 1.8349 shares of Common Stock, determined by dividing $50 by the applicable market value
Less than $27.2494 (initial price)	1.8349 shares of Common Stock

Optional Conversion of the Holder. Other than during a fundamental change conversion period, and unless CenterPoint Energy has redeemed the Series B Preferred Stock, a holder of the Series B Preferred Stock may, at any time prior to September 1, 2021, elect to convert such holder’s shares of the Series B Preferred Stock, in whole or in part, at the minimum conversion rate of 30.5820 shares of Common Stock per share of the Series B Preferred Stock (equivalent to 1.5291 shares of Common Stock per depositary share), subject to certain anti-dilution and other adjustments. Because each depositary share represents a 1/20th fractional interest in a share of the Series B Preferred Stock, a holder of depositary shares may convert its depositary shares only in lots of 20 depositary shares.

Fundamental Change Conversion. If a fundamental change occurs on or prior to September 1, 2021, holders of the Series B Preferred Stock will have the right to convert their shares of the Series B Preferred Stock, in whole or in part, into shares of Common Stock at the fundamental change conversion rate during the period beginning on, and including, the effective date of such fundamental change and ending on, and including, the date that is 20 calendar days after such effective date (or, if later, the date that is 20 calendar days after holders receive notice of such fundamental change, but in no event later than September 1, 2021). Holders who convert shares of the Series B Preferred Stock during that period will also receive a make-whole dividend amount comprised of a fundamental change dividend make-whole amount, and to the extent there is any, the accumulated dividend amount. Because each depositary share represents a 1/20th fractional interest in a share of the Series B Preferred Stock, a holder of depositary shares may convert its depositary shares upon a fundamental change only in lots of 20 depositary shares.

Ranking. The Series B Preferred Stock, with respect to anticipated dividends and distributions upon CenterPoint Energy’s liquidation or dissolution, or winding-up of CenterPoint Energy’s affairs, ranks or will rank:

• senior to Common Stock and to each other class or series of capital stock established after the initial issue date of the Series B Preferred Stock that is expressly made subordinated to the Series B Preferred Stock;

• on a parity with the Series A Preferred Stock and any class or series of capital stock established after the initial issue date that is not expressly made senior or subordinated to the Series B Preferred Stock;

• junior to any class or series of capital stock established after the initial issue date that is expressly made senior to the Series B Preferred Stock;

• junior to all existing and future indebtedness (including indebtedness outstanding under CenterPoint Energy’s credit facilities, senior notes and commercial paper) and other liabilities with respect to assets available to satisfy claims against CenterPoint Energy; and

• structurally subordinated to any existing and future indebtedness and other liabilities of CenterPoint Energy’s subsidiaries and capital stock of CenterPoint Energy’s subsidiaries held by third parties.

Voting Rights. Holders of the Series B Preferred Stock generally will not have voting rights. Whenever dividends on shares of the Series B Preferred Stock have not been declared and paid for six or more dividend periods (including, for the avoidance of doubt, the dividend period beginning on, and including, the initial issue date and ending on, but excluding, December 1, 2018), whether or not consecutive, the holders of such shares of Series B Preferred Stock, voting together as a single class with holders of any and all other series of voting preferred stock then outstanding (as defined in the Statement of Resolution for the Series B Preferred Stock), will be entitled at CenterPoint Energy’s next annual or special meeting of shareholders to vote for the election of a total of two additional members of CenterPoint Energy’s Board of Directors, subject to certain limitations. This right will terminate if and when all accumulated and unpaid dividends have been paid in full and, upon such termination, the term of office of each director so elected will terminate at such time and the number of directors on CenterPoint Energy’s Board of Directors will automatically decrease by two, subject to the revesting of such rights in the event of each subsequent nonpayment.

Common Stock

On October 1, 2018, CenterPoint Energy completed the issuance of 69,633,027 shares of Common Stock at a price of $27.25 per share, for net proceeds of $1,844 million after issuance costs. The amount issued included 9,082,568 shares of Common Stock issued pursuant to the exercise in full of the option granted to the underwriters to purchase additional shares of Common Stock.

CenterPoint Energy used the net proceeds from the Common Stock offering to fund a portion of the Merger and to pay related fees and expenses.

Undistributed Retained Earnings

As of December 31, 2019 and 2018, CenterPoint Energy’s consolidated retained earnings balance includes undistributed earnings from Enable of $-0- and $31 million, respectively.

Accumulated Other Comprehensive Income (Loss)

Changes in accumulated comprehensive income (loss) are as follows:

	Year Ended December 31,
	2019									2018
	CenterPoint Energy			Houston Electric			CERC			CenterPoint Energy			Houston Electric			CERC
	(in millions)
Beginning Balance	$	(108	)	$	(14	)	$	5		$	(68	)	$	—		$	6
Other comprehensive income (loss) before reclassifications:
Remeasurement of pension and other postretirement plans	7			—			7			(19		)	—			1
Deferred loss from interest rate derivatives (1)	(3		)	(1		)	—			(19		)	(18		)	(1		)
Reclassified to earnings	1			—			—			—			—			—
Other comprehensive loss from unconsolidated affiliates	(1		)	—			—			—			—			—
Amounts reclassified from accumulated other comprehensive loss:
Prior service cost (2)	1			—			—			1			—			1
Actuarial losses (2)	8			—			—			6			—			—
Tax benefit (expense)	(3		)	—			(2		)	6			4			(1		)
Net current period other comprehensive income (loss)	10			(1		)	5			(25		)	(14		)	—
Adoption of ASU 2018-02	—			—			—			(15		)	—			(1		)
Ending Balance	$	(98	)	$	(15	)	$	10		$	(108	)	$	(14	)	$	5

(1) Gains and losses are reclassified from Accumulated other comprehensive income into income when the hedged transactions affect earnings. The reclassification amounts are included in Interest and other finance charges in each of the Registrant’s respective Statements of Consolidated Income. Amounts are $1 million and less than $1 million for the years ended December 31, 2019 and 2018, respectively.

(2)

Amounts are included in the computation of net periodic cost and are reflected in Other, net in each of the Registrants’ respective Statements of Consolidated Income.

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Mergers and Acquisitions (Tables)

12 Months Ended

Dec. 31, 2019

Business Combinations [Abstract]

Schedule of Business Acquisitions, by Acquisition [Table Text Block]

The Merger is being accounted for in accordance with ASC 805, Business Combinations, with CenterPoint Energy as the accounting acquirer of Vectren. Identifiable assets acquired and liabilities assumed have been recorded at their estimated fair values on the Merger Date.

Vectren’s regulated operations, comprised of electric generation and electric and natural gas energy delivery services, are subject to the rate-setting authority of the FERC, the IURC and the PUCO, and are accounted for pursuant to U.S. generally accepted accounting principles for regulated operations. The rate-setting and cost-recovery provisions currently in place for Vectren’s regulated operations provide revenues derived from costs including a return on investment of assets and liabilities included in rate base. Thus, the fair value of Vectren’s tangible and intangible assets and liabilities subject to these rate-setting

provisions approximate their carrying values on the Merger Date.  The fair value of regulatory assets not earning a return have been determined using the income approach and are considered Level 3 fair value measurements due to the use of significant judgmental and unobservable inputs.

The fair value of Vectren’s assets acquired and liabilities assumed that are not subject to the rate-setting provisions, including identifiable intangibles, have been determined using the income approach and the market approach. The valuation of Vectren’s long-term debt is primarily considered a Level 2 fair value measurement. All other valuations are considered Level 3 fair value measurements due to the use of significant judgmental and unobservable inputs, including projected timing and amount of future cash flows and discount rates reflecting risk inherent in the future market prices.

The following table presents the purchase price allocation as of December 31, 2019 (in millions):

Cash and cash equivalents	$	16
Other current assets	577
Property, plant and equipment, net	5,147
Identifiable intangibles	297
Regulatory assets	338
Other assets	141
Total assets acquired	6,516
Current liabilities	648
Regulatory liabilities	938
Other liabilities	886
Long-term debt	2,401
Total liabilities assumed	4,873
Net assets acquired	1,643
Goodwill	4,339
Total purchase price consideration	$	5,982

Schedule of Finite-Lived Intangible Assets Acquired as Part of Business Combination [Table Text Block]

The fair value of the identifiable intangible assets and related useful lives as included in the purchase price allocation as of December 31, 2019 include:

	Weighted Average Useful Lives	Estimated Fair Value
	(in years)	(in millions)
Operation and maintenance agreements	24	$	12
Customer relationships	18	200
Construction backlog	1	27
Trade names	10	58
Total		$	297

Business Combination, Separately Recognized Transactions [Table Text Block]

The results of operations for Vectren included in CenterPoint Energy’s Consolidated Financial Statements from the Merger Date for the year ended December 31, 2019 are as follows:

	(in millions)
Operating revenues	$	2,729
Net income	190

Business Acquisition, Pro Forma Information [Table Text Block]

The following unaudited pro forma financial information reflects the consolidated results of operations of CenterPoint Energy, assuming the Merger had taken place on January 1, 2018. The unaudited pro forma financial information has been presented for illustrative purposes only and is not necessarily indicative of the consolidated results of operations that would have been achieved had the Merger taken place on the dates indicated or of the future consolidated results of operations of the combined company.

	Year Ended December 31,
	2019			2018
	(in millions)
Operating revenues	$	12,547		$	13,282
Net income	812		(1)	458		(2)

(1) Pro forma net income was adjusted to exclude $37 million of Vectren Merger-related transaction costs incurred in 2019.

(2)

Pro forma net income was adjusted to include $37 million of Vectren Merger-related transaction costs incurred in 2019.

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Supplemental Disclosure of Cash Flow Information

12 Months Ended

Dec. 31, 2019

Supplemental Cash Flow Elements [Abstract]

Supplemental Disclosure of Cash Flow Information [Text Block]

(20) Supplemental Disclosure of Cash Flow Information

The tables below provide supplemental disclosure of cash flow information:

	2019						2018						2017
	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC
	(in millions)
Cash Payments/Receipts:
Interest, net of capitalized interest	$	436	$	229	$	109	$	363	$	200	$	105	$	378	$	205	$	116
Income taxes (refunds), net	155		87		7		89		154		3		15		76		4
Non-cash transactions:
Accounts payable related to capital expenditures	236		117		86		201		124		80		144		104		56
Capital distribution associated with the Internal Spin (1)	—		—		28		—		—		1,473		—		—		—
ROU assets obtained in exchange for lease liabilities (2)	44		1		29		—		—		—		—		—		—

(1) The capital distribution in 2019 associated with the Internal Spin is a result of the return to accrual for the periods of CERC’s ownership during 2018.

(2) Includes the transition impact of adoption of ASU 2016-02 Leases as of January 1, 2019. The Registrants elected not to recast comparative periods in the year of adoption as permitted by the standard.

The table below provides a reconciliation of cash, cash equivalents and restricted cash reported in the Consolidated Balance Sheets to the amount reported in the Statements of Consolidated Cash Flows:

	December 31, 2019						December 31, 2018
	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC
	(in millions)
Cash and cash equivalents (1) (2)	$	241	$	216	$	2	$	4,231	$	335	$	14
Restricted cash included in Prepaid expenses and other current assets	30		19		—		46		34		11
Restricted cash included in Other	—		—		—		1		1		—
Total cash, cash equivalents and restricted cash shown in Statements of Consolidated Cash Flows	$	271	$	235	$	2	$	4,278	$	370	$	25

(1) CenterPoint Energy’s Cash and cash equivalents as of December 31, 2018 included $3.9 billion of temporary investments resulting from the Merger financings. CenterPoint Energy recorded interest income of $22 million, $28 million and $2 million for the years ended December 31, 2019, 2018 and 2017, respectively, in Other, net on CenterPoint Energy’s Statements of Consolidated Income. See Notes 13 and 14 for further details related to the Merger financings.

(2)

Houston Electric’s Cash and cash equivalents as of December 31, 2019 and 2018 included $216 million and $335 million, respectively, of cash related to the Bond Companies. Houston Electric recorded interest income of $9 million, $4 million and $2 million for the years ended December 31, 2019, 2018 and 2017, respectively, in Other, net on Houston Electric’s Statement of Consolidated Income.

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2019

Accounting Policies [Abstract]

Use of Estimates

Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Principles of Consolidation

Principles of Consolidation

The accounts of the Registrants and their wholly-owned and majority-owned and controlled subsidiaries are included in the consolidated financial statements. All intercompany transactions and balances are eliminated in consolidation, except as described below.

Businesses within the Infrastructure Services reportable segment provide underground pipeline construction and repair services for customers that include NGD utilities. In accordance with consolidation guidance in ASC 980—Regulated Operations, costs incurred by NGD utilities for these pipeline construction and repair services are not eliminated in consolidation when capitalized and included in rate base by the NGD utility. Fees incurred by CenterPoint Energy’s and CERC’s NGD for pipeline construction and repair services that were capitalized totaled $162 million and $20 million, respectively, for the 11 months ended December 31, 2019.

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 is expected to close in the second quarter of 2020. For further information, see Notes 6 and 23.

As of December 31, 2019, CenterPoint Energy and Houston Electric had VIEs consisting of the Bond Companies, which are consolidated. The consolidated VIEs are wholly-owned, bankruptcy remote special purpose entities that were formed solely for the purpose of securitizing transition and system restoration related property. Creditors of CenterPoint Energy and Houston Electric have no recourse to any assets or revenues of the Bond Companies. The bonds issued by these VIEs are payable only from and secured by transition and system restoration property and the bondholders have no recourse to the general credit of CenterPoint Energy or Houston Electric.

Equity and Investments without a Readily Determinable Fair Value (CenterPoint Energy and CERC)

Equity and Investments without a Readily Determinable Fair Value (CenterPoint Energy)

CenterPoint Energy generally uses the equity method of accounting for investments in entities in which it has an ownership interest between 20% and 50% and exercises significant influence. CenterPoint Energy also uses the equity method for investments in which it has ownership percentages greater than 50%, when it exercises significant influence, does not have control and is not considered the primary beneficiary, if applicable.

Under the equity method, CenterPoint Energy adjusts its investments each period for contributions made, distributions received, respective shares of comprehensive income and amortization of basis differences, as appropriate. CenterPoint Energy evaluates its equity method investments for impairment when events or changes in circumstances indicate there is a loss in value of the investment that is other than a temporary decline.

CenterPoint Energy considers distributions received from equity method investments which do not exceed cumulative equity in earnings subsequent to the date of investment to be a return on investment and classifies these distributions as operating activities in its Statements of Consolidated Cash Flows. CenterPoint Energy considers distributions received from equity method investments in excess of cumulative equity in earnings subsequent to the date of investment to be a return of investment and classifies these distributions as investing activities in its Statements of Consolidated Cash Flows.

Investments without a readily determinable fair value will be measured at cost, less impairment, plus or minus observable prices changes of an identical or similar investment of the same issuer.

Revenues

Revenues

The Registrants record revenue for electricity delivery and natural gas sales and services under the accrual method and these revenues are recognized upon delivery to customers. Electricity deliveries not billed by month-end are accrued based on actual AMS data, daily supply volumes and applicable rates. Natural gas sales not billed by month-end are accrued based upon estimated purchased gas volumes, estimated lost and unaccounted for gas and currently effective tariff rates. Revenue for some pipeline construction services are based on the percentage of completion method. For further discussion, see Note 5.

MISO Transactions

MISO Transactions

Indiana Electric is a member of the MISO. MISO-related purchase and sale transactions are recorded using settlement information provided by the MISO. These purchase and sale transactions are accounted for on at least a net hourly position, meaning net purchases within that interval are recorded on CenterPoint Energy’s Statements of Consolidated Income in Utility natural gas, fuel and purchased power, and net sales within that interval are recorded on CenterPoint Energy’s Statements of Consolidated Income in Utility revenues. On occasion, prior period transactions are resettled outside the routine process due to a change in the MISO’s tariff or a material interpretation thereof. Expenses associated with resettlements are recorded once the resettlement is probable and the resettlement amount can be estimated. Revenues associated with resettlements are recognized when the amount is determinable and collectability is reasonably assured.

Guarantees

Guarantees

CenterPoint Energy recognizes guarantee obligations at fair value. CenterPoint Energy discloses parent company guarantees of a subsidiary’s obligation when that guarantee results in the exposure of a material obligation of the parent company even if the probability of fulfilling such obligation is considered remote. See Note 16(c) and (d).  

Long-lived Assets, Goodwill and Intangibles

Long-lived Assets, Goodwill and Intangibles

The Registrants record property, plant and equipment at historical cost and expense repair and maintenance costs as incurred.

The Registrants periodically evaluate long-lived assets, including property, plant and equipment, and specifically identifiable intangibles subject to amortization, when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable. For rate regulated businesses, recoverability of long-lived assets is assessed by determining if a capital disallowance from a regulator is probable through monitoring the outcome of rate cases and other proceedings. For non-rate regulated businesses, recoverability is assessed based on an estimate of undiscounted cash flows attributable to the assets compared to the carrying value of the assets. As of December 31, 2019, CenterPoint Energy and CERC, as applicable, determined that the carrying value of long-lived and intangible assets associated with the Infrastructure Services and Energy Services reporting units were recoverable based on undiscounted cash flows, considering the likelihood of possible outcomes existing as of that date, including the assessment of the likelihood of a future sale of these assets. No long-lived asset or intangible asset impairments were recorded in 2019, 2018 or 2017.

CenterPoint Energy and CERC perform goodwill impairment tests at least annually and evaluate goodwill when events or changes in circumstances indicate that its carrying value may not be recoverable. Subsequent to the Registrant’s adoption of ASU 2017-04 Simplifying the Test for Goodwill Impairment on January 1, 2018, CenterPoint Energy and CERC recognize a goodwill impairment by the amount a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill within that reporting unit. CenterPoint Energy includes deferred tax assets and liabilities within its reporting unit’s carrying value for the purposes of annual and interim impairment tests, regardless of whether the estimated fair value reflects the disposition of such assets and liabilities. For further information about the goodwill impairment tests during 2019, see Note 6.

Assets Held for Sale and Discontinued Operations

Assets Held for Sale and Discontinued Operations

Generally, a long-lived asset to be sold is classified as held for sale in the period in which management, with approval from the Board of Directors, as applicable, commits to a plan to sell and a sale is expected to be completed within one year. The Registrants record assets and liabilities held for sale at the lower of their carrying value or their estimated fair value less cost to sell. If the disposal group reflects a component of a reporting unit and meets the definition of a business, the goodwill within that reporting unit is allocated to the disposal group based on the relative fair value of the components representing a business that will be retained and disposed. Goodwill is not allocated to a portion of a reporting unit that does not meet the definition of a business. A disposal group that meets the held for sale criteria and also represents a strategic shift to the Registrant, is also reflected as discontinued operations on the Statements of Consolidated Income, and prior periods are recast to reflect the earnings or losses from such businesses as income from discontinued operations, net of tax.

Regulatory Assets and Liabilities

Regulatory Assets and Liabilities

The Registrants apply the guidance for accounting for regulated operations to the Houston Electric T&D reportable segment, Indiana Electric Integrated segment and the Natural Gas Distribution reportable segment. The Registrants’ rate-regulated subsidiaries may collect revenues subject to refund pending final determination in rate proceedings. In connection with such revenues, estimated rate refund liabilities are recorded which reflect management’s current judgment of the ultimate outcomes of the proceedings.

The Registrants’ rate-regulated businesses recognize removal costs as a component of depreciation expense in accordance with regulatory treatment. In addition, a portion of the amount of removal costs collected from customers that relate to AROs has been reflected as an asset retirement liability in accordance with accounting guidance for AROs.

For further detail on the Registrants’ regulatory assets and liabilities, see Note 7.

Depreciation and Amortization Expense

Depreciation and Amortization Expense

The Registrants compute depreciation and amortization using the straight-line method based on economic lives or regulatory-mandated recovery periods. Amortization expense includes amortization of certain regulatory assets and other intangibles.

Capitalization of Interest and AFUDC

Capitalization of Interest and AFUDC

The Registrants capitalize interest and AFUDC as a component of projects under construction and amortize it over the assets’ estimated useful lives once the assets are placed in service. AFUDC represents the composite interest cost of borrowed funds and a reasonable return on the equity funds used for construction for subsidiaries that apply the guidance for accounting for regulated operations. Although AFUDC increases both utility plant and earnings, it is realized in cash when the assets are included in rates.

	Year Ended December 31,
	2019						2018						2017
	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC
	(in millions)
Interest and AFUDC debt (1)	$	36	$	8	$	3	$	8	$	6	$	2	$	9	$	6	$	2
AFUDC equity (2)	22		15		3		12		10		2		11		10		1

(1) Included in Interest and other finance charges on the Registrants’ respective Statements of Consolidated Income.

(2)

Included in Other Income (Expense) on the Registrants’ respective Statements of Consolidated Income.

Income Taxes

Income Taxes

Houston Electric and CERC are included in CenterPoint Energy’s U.S. federal consolidated income tax return. Houston Electric and CERC report their income tax provision on a separate entity basis pursuant to a tax sharing agreement with CenterPoint Energy. Current federal and certain state income taxes are payable to or receivable from CenterPoint Energy.

The Registrants use the asset and liability method of accounting for deferred income taxes. Deferred income tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. A valuation allowance is established against deferred tax

assets for which management believes realization is not considered to be more likely than not. The Registrants recognize interest and penalties as a component of income tax expense (benefit), as applicable, in their respective Statements of Consolidated Income. CenterPoint Energy reports the income tax provision associated with its interest in Enable in income tax expense (benefit) in its Statements of Consolidated Income.

On December 22, 2017, President Trump signed into law comprehensive tax reform legislation informally called the Tax Cuts and Jobs Acts, or TCJA, which resulted in significant changes to federal tax laws effective January 1, 2018. See Note 15 for further discussion of the impacts of tax reform implementation.

To the extent certain EDIT of the Registrants’ rate-regulated subsidiaries may be recoverable or payable through future rates, regulatory assets and liabilities have been recorded, respectively.

The Registrants use the portfolio approach to recognize income tax effects on other comprehensive income from accumulated other comprehensive income.

Investment tax credits are deferred and amortized to income over the approximate lives of the related property.

Accounts Receivable and Allowance for Doubtful Accounts

Accounts Receivable and Allowance for Doubtful Accounts

Accounts receivable are recorded at the invoiced amount and do not bear interest. Management reviews the outstanding accounts receivable, as well as the bad debt write-offs experienced in the past, and establishes an allowance for doubtful accounts. Account balances are charged off against the allowance when management determines it is probable the receivable will not be recovered.

The table below summarizes the Registrants’ provision for doubtful accounts for 2019, 2018 and 2017:

	Year Ended December 31,
	2019						2018						2017
	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC
	(in millions)
Provision for doubtful accounts	$	16	$	—	$	12	$	16	$	—	$	16	$	14	$	1	$	13

Inventory

Inventory

The Registrants’ inventory consists principally of materials and supplies, and for CERC, natural gas, and for CenterPoint Energy, coal inventory. Materials and supplies are valued at the lower of average cost or market. Materials and supplies are recorded to inventory when purchased and subsequently charged to expense or capitalized to plant when installed. Natural gas inventories of CERC’s Energy Services reportable segment at locations qualifying for and utilizing the fair value hedge accounting election are valued at fair value; inventories at locations not qualifying for or not utilizing the fair value hedge accounting election are valued at the lower of average cost or market. During 2019, 2018 and 2017, CERC recorded write-downs of natural gas inventory to the lower of average cost or market which are disclosed on the respective Statements of Consolidated Cash Flows.

Derivative Instruments

Derivative Instruments

The Registrants are exposed to various market risks. These risks arise from transactions entered into in the normal course of business. The Registrants utilize derivative instruments such as physical forward contracts, swaps and options to mitigate the impact of changes in commodity prices, weather and interest rates on operating results and cash flows. Such derivatives are recognized in the Registrants’ Consolidated Balance Sheets at their fair value unless the Registrant elects the normal purchase and sales exemption for qualified physical transactions. A derivative may be designated as a normal purchase or normal sale if the intent is to physically receive or deliver the product for use or sale in the normal course of business. CenterPoint Energy and CERC have elected to record changes in the fair value of amounts excluded from the assessment of effectiveness immediately in their Statements of Consolidated Income.

CenterPoint Energy has a Risk Oversight Committee composed of corporate and reportable segment officers that oversees commodity price, weather and credit risk activities, including the Registrants’ marketing, risk management services and hedging activities. The committee’s duties are to establish the Registrants’ commodity risk policies, allocate board-approved commercial risk limits, approve the use of new products and commodities, monitor positions and ensure compliance with the Registrants’ risk

management policies and procedures and limits established by CenterPoint Energy’s Board of Directors. The Registrants’ policies prohibit the use of leveraged financial instruments. A leveraged financial instrument, for this purpose, is a transaction involving a derivative whose financial impact will be based on an amount other than the notional amount or volume of the instrument.

Investments in Equity Securities (CenterPoint Energy and CERC)

Investments in Equity Securities (CenterPoint Energy and CERC)

CenterPoint Energy and CERC report equity securities at estimated fair value in their respective Consolidated Balance Sheets, and any unrealized holding gains and losses are recorded as Other Income (Expense) in their respective Statements of Consolidated Income.

Environmental Costs

Environmental Costs

The Registrants expense or capitalize environmental expenditures, as appropriate, depending on their future economic benefit. The Registrants expense amounts that relate to an existing condition caused by past operations that do not have future economic benefit. The Registrants record undiscounted liabilities related to these future costs when environmental assessments and/or remediation activities are probable and the costs can be reasonably estimated.

Cash and Cash Equivalents and Restricted Cash

Cash and Cash Equivalents and Restricted Cash

For purposes of reporting cash flows, the Registrants consider cash equivalents to be short-term, highly-liquid investments with maturities of three months or less from the date of purchase. Cash and cash equivalents held by the Bond Companies (VIEs) solely to support servicing the Securitization Bonds as of December 31, 2019 and 2018 are reflected on CenterPoint Energy’s and Houston Electric’s Consolidated Balance Sheets.

In connection with the issuance of Securitization Bonds, CenterPoint Energy and Houston Electric were required to establish restricted cash accounts to collateralize the bonds that were issued in these financing transactions. These restricted cash accounts are not available for withdrawal until the maturity of the bonds and are not included in cash and cash equivalents. For more information on restricted cash see Note 20

Preferred Stock Dividends

Preferred Stock and Dividends

Preferred stock is evaluated to determine balance sheet classification, and all conversion and redemption features are evaluated for bifurcation treatment. Proceeds received net of issuance costs are recognized on the settlement date. Cash dividends become a liability once declared. Income available to common stockholders is computed by deducting from net income the dividends accumulated and earned during the period on cumulative preferred stock.

Purchase Accounting

Purchase Accounting

The Registrants evaluate acquisitions to determine when a set of acquired activities and assets represent a business. When control of a business is obtained, the Registrants apply the acquisition method of accounting and record the assets acquired, liabilities assumed and any non-controlling interest obtained based on fair value at the acquisition date. The excess of the fair value of purchase consideration over the fair value of the net assets acquired is recorded as goodwill. The results of operations of the acquired business are included in the Registrants’ respective Statements of Consolidated Income beginning on the date of the acquisition.

New Accounting Pronouncements

New Accounting Pronouncements

The following table provides an overview of certain recently adopted or issued accounting pronouncements applicable to all the Registrants, unless otherwise noted.

Recently Adopted Accounting Standards
ASU Number and Name	Description	Date of Adoption	Financial Statement Impact upon Adoption
ASU 2016-02- Leases (Topic 842) and related amendments	ASU 2016-02 provides a comprehensive new lease model that requires lessees to recognize assets and liabilities for most leases and would change certain aspects of lessor accounting. Transition method: modified retrospective	January 1, 2019	The Registrants adopted the standard and recognized a right-of-use asset and lease liability on their statement of financial position with no material impact on their results of operations and cash flows. See Note 22 for more information.

Issued, Not Yet Effective Accounting Standards
ASU Number and Name	Description	Effective Date	Financial Statement Impact upon Adoption
ASU 2016-13- Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments	This standard, including standards amending this standard, requires a new model called CECL to estimate credit losses for (1) financial assets subject to credit losses and measured at amortized cost and (2) certain off-balance sheet credit exposures. Upon initial recognition of the exposure, the CECL model requires an entity to estimate the credit losses expected over the life of an exposure based on historical information, current information and reasonable and supportable forecasts, including estimates of prepayments. Transition method: modified retrospective	January 1, 2020 Early adoption is permitted	The adoption of this standard will result in an immaterial adjustment to the carrying value of the Registrants’ accounts receivable, net. The adoption of this standard will not have a material impact on the Registrants’ financial position, results of operations or cash flows.
ASU 2018-13- Fair Value Measurement (Topic 820): Disclosure Framework-Changes to the Disclosure Requirements for Fair Value Measurement	This standard eliminates, modifies and adds certain disclosure requirements for fair value measurements. Transition method: prospective for additions and one modification and retrospective for all other amendments	Adoption of eliminations and modifications as of September 30, 2018; Additions will be adopted January 1, 2020	The adoption of this standard did not impact the Registrants’ financial position, results of operations or cash flows. Note 10 reflects the disclosures modified upon adoption.
ASU 2018-15-Intangibles-Goodwill and Other- Internal-Use Software (Subtopic 350-40): Customer's Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract	This standard aligns accounting for implementation costs incurred in a cloud computing arrangement that is accounted for as a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. The update also prescribes the balance sheet, income statement and cash flow classification of the capitalized implementation costs and related amortization expense and requires additional quantitative and qualitative disclosures. Transition method: retrospective or prospective	January 1, 2020 Early adoption is permitted	The adoption of this standard will require the Registrants to capitalize certain costs to implement cloud computing arrangements that are accounted for as service contracts within Prepaid expenses and other current assets on the Registrants’ consolidated balance sheets and record the amortization of such assets within Operation and maintenance expenses on the Registrants’ statements of consolidated income. The adoption of this standard will not have a material impact on the Registrants’ financial position, results of operations, cash flows or disclosures.

Management believes that other recently adopted standards and recently issued standards that are not yet effective will not have a material impact on the Registrants’ financial position, results of operations or cash flows upon adoption.

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Regulatory Matters

12 Months Ended

Dec. 31, 2019

Regulated Operations [Abstract]

Regulatory Accounting [Text Block]

Regulatory Matters

The following is a list of regulatory assets and liabilities reflected on the Registrants’ respective Consolidated Balance Sheets as of December 31, 2019 and 2018. The “amortization through” columns indicate the latest year when a regulatory asset or regulatory liability category will be fully amortized:

	December 31, 2019
	CenterPoint Energy				Houston Electric				CERC
	Amortization Through	(in millions)			Amortization Through	(in millions)			Amortization Through	(in millions)
Regulatory Assets:
Current regulatory assets (1)	2020	$	12		n/a	$	—		2020	$	12
Non-current regulatory assets:
Securitized regulatory assets	2024	788			2024	788			n/a	—
Unrecognized equity return (2)	2024	(168		)	2024	(168		)	n/a	—
Unamortized loss on reacquired debt (3)	2046	62			2046	62			n/a	—
Pension and postretirement-related regulatory asset (3)	Various (a)	637			TBD (b)	34			Various (a)	22
Hurricane Harvey restoration costs (3)	Various	68			TBD (b)	64			TBD (c)	4
Regulatory assets related to TCJA (3) (4)	Various	30			TBD (b)	23			2023	7
Asset retirement obligation (3)	Perpetual	131			Perpetual	26			Perpetual	94
Other regulatory assets-not earning a return (5)	Various (d)	147			Various	57			Various	48
Other regulatory assets	Various	422			Various	29			Various	16
Total non-current regulatory assets		2,117				915				191
Total regulatory assets		2,129				915				203
Regulatory Liabilities:
Current regulatory liabilities (6)	2020	47			n/a	—			2020	47
Non-current regulatory liabilities:
Regulatory liabilities related to TCJA (4)	Various	1,582			TBD (b)	821			Various	442
Estimated removal costs	Various	1,429			Various	244			Various	637
Other regulatory liabilities	Various	463			Various	223			Various	140
Total non-current regulatory liabilities		3,474				1,288				1,219
Total regulatory liabilities		3,521				1,288				1,266
Total regulatory assets and liabilities, net		$	(1,392	)		$	(373	)		$	(1,063	)

(a) Pension and postretirement-related regulatory assets balances are measured annually, and the ending amortization period may change based on the actuarial valuation.

(b) The recovery and amortization of these amounts are to be determined upon receipt of the final order.

(c) The recovery and amortization of a portion of these amounts are expected to be determined in the next rate case.

(d) Other regulatory assets not-earning a return includes items with different amortization periods; therefore, the amortization is accounted for through various periods.

	December 31, 2018
	CenterPoint Energy			Houston Electric			CERC
	(in millions)
Regulatory Assets:
Current regulatory assets (1)	$	77		$	—		$	77
Non-current regulatory assets:
Securitized regulatory assets	1,059			1,059			—
Unrecognized equity return (2)	(213		)	(213		)	—
Unamortized loss on reacquired debt (3)	68			68			—
Pension and postretirement-related regulatory asset (3)	725			33			30
Hurricane Harvey restoration costs (3)	68			64			4
Regulatory assets related to TCJA (3) (4)	33			23			10
Asset retirement obligation (3)	109			24			85
Other regulatory assets-not earning a return (3)	81			55			26
Other regulatory assets	37			11			26
Total non-current regulatory assets	1,967			1,124			181
Total regulatory assets	2,044			1,124			258
Regulatory Liabilities:
Current regulatory liabilities (6)	38			17			21
Non-current regulatory liabilities:
Regulatory liabilities related to TCJA (4)	1,323			847			476
Estimated removal costs	886			269			617
Other regulatory liabilities	316			182			134
Total non-current regulatory liabilities	2,525			1,298			1,227
Total regulatory liabilities	2,563			1,315			1,248
Total regulatory assets and liabilities, net	$	(519	)	$	(191	)	$	(990	)

(1) Current regulatory assets are included in Prepaid expenses and other current assets in the Registrants’ respective Consolidated Balance Sheets.

(2) The unrecognized equity return will be recognized as it is recovered in rates through 2024. The timing of CenterPoint Energy’s and Houston Electric’s recognition of the equity return will vary each period based on amounts actually collected during the period. The actual amounts recognized are adjusted at least annually to correct any over-collections or under-collections during the preceding 12 months.

	Year Ended December 31,
	2019				2018				2017
	CenterPoint Energy		Houston Electric		CenterPoint Energy		Houston Electric		CenterPoint Energy		Houston Electric
Allowed equity return recognized	$	45	$	45	$	74	$	74	$	42	$	42

(3) Substantially all of these regulatory assets are not earning a return.

(4) The EDIT and deferred revenues will be recovered or refunded to customers as required by tax and regulatory authorities. See Note 15 for additional information.

(5) Regulatory assets acquired in the Merger and not earning a return were recorded at fair value as of the Merger Date. Such fair value adjustments are recognized over time until the regulatory asset is recovered.

(6) Current regulatory liabilities are included in Other current liabilities in each of the Registrants’ respective Consolidated Balance Sheets.

Houston Electric Base Rate Case (CenterPoint Energy and Houston Electric)

On April 5, 2019, and subsequently adjusted in errata filings in May and June 2019, Houston Electric filed its base rate application with the PUCT and the cities in its service area seeking approval for revenue increases of approximately $194 million, exclusive of the EDIT refund discussed below.

The key proposals of the base rate case included:

• a rate base of $6.4 billion with a 50% debt/50% equity capital structure and a 10.4% ROE;

• a prudency determination on all capital investments made by Houston Electric since January 1, 2010;

• the establishment of a rider to refund unprotected EDIT resulting from the TCJA; and

• updated depreciation rates and approval to recover other costs.

On September 16, 2019, the ALJs issued a PFD. The PUCT began deliberating on the PFD (which is prepared by ALJs at a different state agency) during its November 14, 2019 open meeting, but delayed final determination for further consideration. The PUCT again discussed the Houston Electric rate case at its December 13, 2019 open meeting and concluded that the PUCT would consider settlement a reasonable approach to resolving the rate case and noted that Houston Electric had indicated settlement negotiations were already underway. Houston Electric updated the PUCT at its January 16, 2020 open meeting regarding the status of settlement discussions, indicating that the parties were working on a settlement and anticipated a final settlement in the near future. On January 23, 2020, Houston Electric filed a Stipulation and Settlement Agreement with the PUCT, which provides for the following, among other things:

• an overall revenue requirement increase of approximately $13 million;

• an ROE of 9.4%;

• a capital structure of 57.5% debt/42.5% equity;

• a refund of unprotected EDIT of $105 million plus carrying costs over approximately 30-36 months; and

• recovery of all retail transmission related costs through the TCRF.

Also, Houston Electric is not required to make a one-time refund of capital recovery from its TCOS and DCRF mechanisms. Future TCOS filings will take into account both ADFIT and EDIT until the final order from Houston Electric’s next base rate proceeding. No rate base items are expected to be written off; however, approximately $12 million in rate case expenses were written off in 2019. A base rate case application must be filed for Houston Electric no later than four years from the date of the PUCT’s final order in the proceeding. Additionally, Houston Electric will not file a DCRF in 2020, nor will a subsequent separate proceeding with the PUCT be instituted regarding EDIT on Houston Electric’s securitized assets.

Furthermore, under the terms of the Stipulation and Settlement Agreement, Houston Electric agreed to adopt certain ring-fencing measures to increase its financial separateness from CenterPoint Energy, which include the following:

• Houston Electric’s credit agreements and indentures shall not contain cross-default provisions by which a default by CenterPoint Energy or its other affiliates would cause a default at Houston Electric;

• The financial covenant in Houston Electric’s credit agreement shall not be related to any entity other than Houston Electric. Houston Electric shall not include in its debt or credit agreements any financial covenants or rating agency triggers related to any entity other than Houston Electric;

• Houston Electric shall not pledge its assets in respect of or guarantee any debt or obligation of any of its affiliates. Houston Electric shall not pledge, mortgage, hypothecate, or grant a lien upon the property of Houston Electric except pursuant to an exception in effect in Houston Electric’s current credit agreement, such as Houston Electric’s first mortgage and general mortgage;

• Houston Electric shall maintain its own stand-alone credit facility, and Houston Electric shall not share its credit facility with any regulated or unregulated affiliate;

• Houston Electric shall maintain ratings with all three major credit ratings agencies;

• Houston Electric shall maintain a stand-alone credit rating;

• Houston Electric’s first mortgage bonds and general mortgage bonds shall be secured only with assets of Houston Electric;

• No Houston Electric assets may be used to secure the debt of CenterPoint Energy or its other affiliates;

• Houston Electric shall not hold out its credit as being available to pay the debt of any affiliates (provided that, for the avoidance of doubt, Houston Electric is not considered to be holding its credit out to pay the debt of affiliates, or in breach of any other ring-fencing measure, with respect to the $68 million of Houston Electric general mortgage bonds that currently serve as collateral for certain outstanding CenterPoint Energy pollution control bonds);

• Without prior approval of the PUCT, neither CenterPoint Energy nor any affiliate of CenterPoint Energy (excluding Houston Electric) may incur, guarantee, or pledge assets in respect of any incremental new debt that is dependent on: (1) the revenues of Houston Electric in more than a proportionate degree than the other revenues of CenterPoint Energy; or (2) the equity of Houston Electric;

• Houston Electric shall not transfer any material assets or facilities to any affiliates, other than a transfer that is on an arm’s length basis consistent with the PUCT’s affiliate standards applicable to Houston Electric;

• Except for its participation in an affiliate money pool, Houston Electric shall not commingle its assets with those of other CenterPoint Energy affiliates;

• Except for its participation in an affiliate money pool, Houston Electric shall not lend money to or borrow money from CenterPoint Energy; and

• Houston Electric shall notify the PUCT if its issuer credit rating or corporate credit rating as rated by any of the three major rating agencies falls below investment grade.

The PUCT approved the settlement at its February 14, 2020 open meeting. A final order from the PUCT is currently expected during the first quarter of 2020; however, motions for rehearing, if granted, could result in the order being issued after the first quarter of 2020. The rates are expected to be implemented 45 days after the final order is issued.

CenterPoint Energy and Houston Electric record pre-tax expense for (i) probable disallowances of capital investments and (ii) customer refund obligations and costs deferred in regulatory assets when recovery of such amounts is no longer considered probable.

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Property, Plant and Equipment

12 Months Ended

Dec. 31, 2019

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment [Text Block]

Property, Plant and Equipment

(a) Property, Plant and Equipment

Property, plant and equipment includes the following:

		December 31, 2019						December 31, 2018
	Weighted Average Useful Lives	Property, Plant and Equipment, Gross		Accumulated Depreciation & Amortization		Property, Plant and Equipment, Net		Property, Plant and Equipment, Gross		Accumulated Depreciation & Amortization		Property, Plant and Equipment, Net
	(in years)	(in millions)
CenterPoint Energy
Electric Transmission & Distribution	37	$	14,360	$	4,634	$	9,726	$	12,148	$	3,746	$	8,402
Electric Generation (1)	27	1,780		698		1,082		—		—		—
Natural Gas Distribution	29	12,695		3,731		8,964		7,257		2,128		5,129
Energy Services (2)	27	136		53		83		121		43		78
Infrastructure Services (3)	10	317		22		295		—		—		—
Other property	19	1,397		602		795		741		306		435
Total		$	30,685	$	9,740	$	20,945	$	20,267	$	6,223	$	14,044
Houston Electric
Electric Transmission	46	$	3,358	$	674	$	2,684	$	3,077	$	650	$	2,427
Electric Distribution	35	7,876		2,586		5,290		7,524		2,553		4,971
Other transmission & distribution property	19	1,595		537		1,058		1,547		543		1,004
Total		$	12,829	$	3,797	$	9,032	$	12,148	$	3,746	$	8,402

		December 31, 2019						December 31, 2018
	Weighted Average Useful Lives	Property, Plant and Equipment, Gross		Accumulated Depreciation & Amortization		Property, Plant and Equipment, Net		Property, Plant and Equipment, Gross		Accumulated Depreciation & Amortization		Property, Plant and Equipment, Net
	(in years)	(in millions)
CERC
Natural Gas Distribution	29	$	7,933	$	2,208	$	5,725	$	7,257	$	2,128	$	5,129
Energy Services (2)	27	136		53		83		121		43		78
Other property	16	55		27		28		53		34		19
Total		$	8,124	$	2,288	$	5,836	$	7,431	$	2,205	$	5,226

(1) SIGECO and AGC own a 300 MW unit at the Warrick Power Plant (Warrick Unit 4) as tenants in common. SIGECO’s share of the cost of this unit as of December 31, 2019, is $194 million with accumulated depreciation totaling $137 million. AGC and SIGECO share equally in the cost of operation and output of the unit. SIGECO’s share of operating costs is included in Operation and maintenance expense in CenterPoint Energy’s Statements of Consolidated Income.

(2) 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. The transaction is expected to close in the second quarter of 2020. For further information, see Notes 6 and 23.

(3) 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 is expected to close in the second quarter of 2020. For further information, see Notes 6 and 23.

(b) Depreciation and Amortization

The following table presents depreciation and amortization expense for 2019, 2018 and 2017:

	Year Ended December 31,
	2019						2018						2017
	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC
	(in millions)
Depreciation	$	920	$	339	$	281	$	626	$	342	$	264	$	619	$	354	$	243
Amortization of securitized regulatory assets	271		271		—		531		531		—		329		329		—
Other amortization	96		38		24		86		44		29		88		41		36
Total	$	1,287	$	648	$	305	$	1,243	$	917	$	293	$	1,036	$	724	$	279

(c) AROs

The Registrants recorded AROs associated with the removal of asbestos and asbestos-containing material in its buildings, including substation building structures. CenterPoint Energy recorded AROs relating to the closure of the ash ponds at A.B. Brown and F.B. Culley. CenterPoint Energy and Houston Electric also recorded AROs relating to treated wood poles for electric distribution, distribution transformers containing PCB (also known as Polychlorinated Biphenyl), and underground fuel storage tanks. CenterPoint Energy and CERC also recorded AROs relating to gas pipelines abandoned in place. The estimates of future liabilities were developed using historical information, and where available, quoted prices from outside contractors.

A reconciliation of the changes in the ARO liability recorded in Other non-current liabilities on each of the Registrants’ respective Consolidated Balance Sheets is as follows:

	December 31, 2019						December 31, 2018
	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy			Houston Electric			CERC
	(in millions)
Beginning balance	$	258	$	34	$	221	$	281		$	35		$	243
Addition from Merger with Vectren	116		—		—		—			—			—
Accretion expense (1)	16		1		10		10			1			9
Revisions in estimates (2)	149		7		94		(33		)	(2		)	(31		)
Ending balance	$	539	$	42	$	325	$	258		$	34		$	221

(1) Reflected in Regulatory assets on each of the Registrants’ respective Consolidated Balance Sheets.

(2)

In 2019, the Registrants reflected an increase in their respective ARO liability, which is primarily attributable to decreases in the long-term interest rates used for discounting in the ARO calculation and increased estimated closure costs for CenterPoint Energy’s electric generation. In 2018, CenterPoint Energy and CERC reflected a decrease in their respective ARO liability, which is primarily attributable to increases in the long-term interest rates used for discounting in the ARO calculation.

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Income Taxes Merger with Vectren (Details) - USD ($) $ in Millions		12 Months Ended
	Feb. 01, 2019	Dec. 31, 2019
Vectren [Member]
Business Acquisition [Line Items]
Cash paid to acquire Vectren	$ 6,000	$ 5,982
Operating loss carryforwards		177
Charitable Contribution [Member]
Business Acquisition [Line Items]
Deferred tax assets tax credit carryforwards		26
Charitable Contribution [Member] | Vectren [Member]
Business Acquisition [Line Items]
Deferred tax assets tax credit carryforwards		$ 60

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Stock-Based Incentive Compensation Plans and Employee Benefit Plans Change in Control Agreements and Other Employee Matters (Details)	12 Months Ended
	Dec. 31, 2019 salary_severance_benefits
Concentration Risk [Line Items]
Maximum Number Of Times Annual Salary Included In Severance Benefits	3
Workforce Subject to Collective Bargaining Arrangements Expiring in May 2020 [Member] | Employees Subject To Collective Bargaining Agreements [Member] | Labor Force Concentration Risk [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	10.00%
Workforce Subject to Collective Bargaining Arrangements Expiring in March and May 2021 [Member] | Employees Subject To Collective Bargaining Agreements [Member] | Labor Force Concentration Risk [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	2.00%
Workforce Subject to Collective Bargaining Arrangements Expiring in April 2020 [Member] | Employees Subject To Collective Bargaining Agreements [Member] | Labor Force Concentration Risk [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	3.00%
Workforce Subject to Collective Bargaining Arrangements Expiring in December 2020 [Member] | Employees Subject To Collective Bargaining Agreements [Member] | Labor Force Concentration Risk [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	4.00%
Workforce Subject to Collective Bargaining Arrangements Expiring in June and July 2022 [Member] | Employees Subject To Collective Bargaining Agreements [Member] | Labor Force Concentration Risk [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	5.00%
Workforce Subject to Collective Bargaining Arrangements Expiring in September 2021 [Member] | Employees Subject To Collective Bargaining Agreements [Member] | Labor Force Concentration Risk [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	0.00%
Workforce Subject to Collective Bargaining Arrangements Expiring in October 2021 [Member] | Employees Subject To Collective Bargaining Agreements [Member] | Labor Force Concentration Risk [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	1.00%
Workforce Subject to Collective Bargaining Arrangements Expiring Various Dates in 2020 to 2022 [Member] | Employees Subject To Collective Bargaining Agreements [Member] | Labor Force Concentration Risk [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	27.00%	[1]
Workforce Subject to Collective Bargaining Arrangements [Member] | Employees Subject To Collective Bargaining Agreements [Member] | Labor Force Concentration Risk [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	52.00%
Houston Electric [Member] | Workforce Subject to Collective Bargaining Arrangements Expiring in May 2020 [Member] | Employees Subject To Collective Bargaining Agreements [Member] | Labor Force Concentration Risk [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	51.00%
Houston Electric [Member] | Workforce Subject to Collective Bargaining Arrangements Expiring in March and May 2021 [Member] | Employees Subject To Collective Bargaining Agreements [Member] | Labor Force Concentration Risk [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	0.00%
Houston Electric [Member] | Workforce Subject to Collective Bargaining Arrangements Expiring in April 2020 [Member] | Employees Subject To Collective Bargaining Agreements [Member] | Labor Force Concentration Risk [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	0.00%
Houston Electric [Member] | Workforce Subject to Collective Bargaining Arrangements Expiring in December 2020 [Member] | Employees Subject To Collective Bargaining Agreements [Member] | Labor Force Concentration Risk [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	0.00%
Houston Electric [Member] | Workforce Subject to Collective Bargaining Arrangements Expiring in June and July 2022 [Member] | Employees Subject To Collective Bargaining Agreements [Member] | Labor Force Concentration Risk [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	0.00%
Houston Electric [Member] | Workforce Subject to Collective Bargaining Arrangements Expiring in September 2021 [Member] | Employees Subject To Collective Bargaining Agreements [Member] | Labor Force Concentration Risk [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	0.00%
Houston Electric [Member] | Workforce Subject to Collective Bargaining Arrangements Expiring in October 2021 [Member] | Employees Subject To Collective Bargaining Agreements [Member] | Labor Force Concentration Risk [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	0.00%
Houston Electric [Member] | Workforce Subject to Collective Bargaining Arrangements Expiring Various Dates in 2020 to 2022 [Member] | Employees Subject To Collective Bargaining Agreements [Member] | Labor Force Concentration Risk [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	0.00%
Houston Electric [Member] | Workforce Subject to Collective Bargaining Arrangements [Member] | Employees Subject To Collective Bargaining Agreements [Member] | Labor Force Concentration Risk [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	51.00%
CERC Corp [Member] | Workforce Subject to Collective Bargaining Arrangements Expiring in May 2020 [Member] | Employees Subject To Collective Bargaining Agreements [Member] | Labor Force Concentration Risk [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	0.00%
CERC Corp [Member] | Workforce Subject to Collective Bargaining Arrangements Expiring in March and May 2021 [Member] | Employees Subject To Collective Bargaining Agreements [Member] | Labor Force Concentration Risk [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	3.00%
CERC Corp [Member] | Workforce Subject to Collective Bargaining Arrangements Expiring in April 2020 [Member] | Employees Subject To Collective Bargaining Agreements [Member] | Labor Force Concentration Risk [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	12.00%
CERC Corp [Member] | Workforce Subject to Collective Bargaining Arrangements Expiring in December 2020 [Member] | Employees Subject To Collective Bargaining Agreements [Member] | Labor Force Concentration Risk [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	7.00%
CERC Corp [Member] | Workforce Subject to Collective Bargaining Arrangements Expiring in June and July 2022 [Member] | Employees Subject To Collective Bargaining Agreements [Member] | Labor Force Concentration Risk [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	12.00%
CERC Corp [Member] | Workforce Subject to Collective Bargaining Arrangements Expiring in September 2021 [Member] | Employees Subject To Collective Bargaining Agreements [Member] | Labor Force Concentration Risk [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	0.00%
CERC Corp [Member] | Workforce Subject to Collective Bargaining Arrangements Expiring in October 2021 [Member] | Employees Subject To Collective Bargaining Agreements [Member] | Labor Force Concentration Risk [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	0.00%
CERC Corp [Member] | Workforce Subject to Collective Bargaining Arrangements Expiring Various Dates in 2020 to 2022 [Member] | Employees Subject To Collective Bargaining Agreements [Member] | Labor Force Concentration Risk [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	0.00%
CERC Corp [Member] | Workforce Subject to Collective Bargaining Arrangements [Member] | Employees Subject To Collective Bargaining Agreements [Member] | Labor Force Concentration Risk [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	34.00%

[1] Infrastructure Services negotiates various trade agreements through contractor associations. The two primary associations are the DCA and the PLCA.  These trade agreements are with a variety of construction unions including Laborer’s International Union of North America, International Union of Operating Engineers, United Association of Journeymen and Apprentices of the Plumbing and Pipe Fitting Industry, and Teamsters. The trade agreements have varying expiration dates in 2020, 2021 and 2022. In addition, these subsidiaries have various project agreements and small local agreements.  These agreements expire upon completion of a specific project or on various dates throughout the year.

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Unconsolidated Affiliate (CenterPoint Energy and CERC) (Details) - USD ($) $ / shares in Units, $ in Millions		3 Months Ended								12 Months Ended
		Dec. 31, 2018		Sep. 30, 2018	[1]	Jun. 30, 2018	[1]	Mar. 31, 2018	[1]	Dec. 31, 2019		Dec. 31, 2018	Dec. 31, 2017
Enable Units [Abstract]
Preferred units - unconsolidated affiliate		$ 363								$ 363		$ 363
Percentage of sales that trigger right of first refusal										5.00%
Enable Distributions [Abstract]
Proceeds from Equity Method Investment, Distribution										$ 261		267	$ 0
Total distributions received from Enable										339		333	333
Equity Method Investment, Summarized Financial Information, Income Statement [Abstract]
Goodwill impairment										48		0	0
CenterPoint Energy’s equity in earnings, net										230		307	265
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity [Abstract]
CenterPoint Energy’s equity method investment in Enable		2,482								2,408		2,482
CERC Corp [Member]
Contribution from parent										129		960	38
Enable Distributions [Abstract]
Total distributions received from Enable												223	297
Equity Method Investment, Summarized Financial Information, Income Statement [Abstract]
Goodwill impairment										48		0	0
Discontinued Operation, Income (Loss) from Discontinued Operation Disclosures [Abstract]
Income tax expense										0		46	104
Income (loss) from discontinued operations, net of tax		(2)	[1]	$ 44		$ 44		$ 52		$ 0		138	161
Enable Midstream Partners [Member]
Share Price										$ 10.03
OGE [Member]
Enable Units [Abstract]
Percentage of sales that trigger right of first refusal										5.00%
Non-utility Investments [Member]
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity [Abstract]
CenterPoint Energy’s equity method investment in Enable	[2]									$ 2
Proliance Holdings LLC [Member]
Equity Method Investment, Summarized Financial Information, Income Statement [Abstract]
CenterPoint Energy’s equity in earnings, net										1		0	0
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity [Abstract]
CenterPoint Energy’s equity method investment in Enable		$ 0										$ 0
Enable Midstream Partners [Member]
Equity Method Investment Decrease in Carrying Value										$ 61
Equity Method Investment Carrying Value Per Unit										$ 10.29
Enable Partnership Interest [Abstract]
Limited partner ownership interest	[3],[4]	54.00%								53.70%		54.00%
Equity Method Investment, Summarized Financial Information, Income Statement [Abstract]
Operating revenues										$ 2,960		$ 3,431	2,803
Cost of sales, excluding depreciation and amortization										1,279		1,819	1,381
Depreciation and amortization										433		398	366
Operating income										569		648	528
Goodwill impairment										86
Net income attributable to Enable common units										360		485	400
CenterPoint Energy’s interest										193		262	216
Basis difference amortization (1)	[5]									47		47	49
Loss on dilution, net of proportional basis difference recognition										(11)		(2)	0
CenterPoint Energy’s equity in earnings, net	[6],[7]									229		307	$ 265
Equity Method Investment, Summarized Financial Information [Abstract]
Current assets		$ 449								389		449
Non-current assets		11,995								11,877		11,995
Current liabilities		1,615								780		1,615
Non-current liabilities		3,211								4,077		3,211
Non-controlling interest		38								37		38
Preferred equity		362								362		362
Equity Method Investment Summarized Financial Information Accumulated Other Comprehensive Income Loss										(3)
Enable partners’ equity		7,218								7,013		7,218
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity [Abstract]
CenterPoint Energy’s ownership interest in Enable partners’ equity		3,896								3,767		3,896
CenterPoint Energy’s basis difference		(1,414)								(1,361)		(1,414)
CenterPoint Energy’s equity method investment in Enable		$ 2,482								$ 2,406		$ 2,482
Enable Midstream Partners [Member] | Common Units [Member]
Enable Distributions [Abstract]
Distribution per share of common units										$ 1.2970		$ 1.2720	$ 1.2720
Proceeds from Equity Method Investment, Distribution										$ 303	[8]	$ 297	$ 297
Enable Midstream Partners [Member] | Series A Preferred Units [Member]
Enable Distributions [Abstract]
Distribution per share of Series A preferred units										$ 2.5000		$ 2.5000	$ 2.5000
Distributions received from Enable cost method investment										$ 36		$ 36	$ 36
Enable Midstream Partners [Member] | CERC Corp [Member] | Common Units [Member]
Enable Distributions [Abstract]
Distribution per share of common units	[8]											$ 0.9540	$ 1.2720
Proceeds from Equity Method Investment, Distribution	[8]											$ 223	$ 297
Common Units [Member] | Enable Midstream Partners [Member]
Enable Units [Abstract]
Limited partner interest units held	[4]	233,856,623								233,856,623		233,856,623
Series A Preferred Units [Member] | Enable Midstream Partners [Member]
Enable Units [Abstract]
Preferred units held	[4],[9]	14,520,000								14,520,000		14,520,000
Natural Gas Expenses [Member] | Enable Midstream Partners [Member]
Transaction with Enable [Abstract]
Natural gas expenses, including transportation and storage costs (1)	[10]									$ 120		$ 122	115
Accounts payable for natural gas purchases from Enable		$ 11								11		11
Natural Gas Expenses [Member] | Enable Midstream Partners [Member] | CERC Corp [Member]
Transaction with Enable [Abstract]
Natural gas expenses, including transportation and storage costs (1)	[10]									120		122	115
Accounts payable for natural gas purchases from Enable		11								11		11
Transitional Service [Member] | Enable Midstream Partners [Member]
Transaction with Enable [Abstract]
Reimbursement of support services (2)	[7]									0		4	4
Accounts receivable for amounts billed for services provided to Enable		2								2		2
Transitional Service [Member] | Enable Midstream Partners [Member] | CERC Corp [Member]
Transaction with Enable [Abstract]
Reimbursement of support services (2)	[7]									0		4	4
Accounts receivable for amounts billed for services provided to Enable		$ 2								$ 2		$ 2
Enable Midstream Partners [Member]
Enable Partnership Interest [Abstract]
Limited partner ownership interest	[3]									100.00%		100.00%
Enable Units [Abstract]
Maximum incentive distribution right										50.00%
Enable Midstream Partners [Member] | OGE [Member]
Enable Partnership Interest [Abstract]
Limited partner ownership interest	[3]									25.50%		25.60%
Enable Midstream Partners [Member] | Public unitholders [Member]
Enable Partnership Interest [Abstract]
Limited partner ownership interest	[3]									20.80%		20.40%
Enable Midstream Partners [Member] | Minimum [Member]
Enable Units [Abstract]
Incentive distribution per unit										$ 0.2875
Enable Midstream Partners [Member] | Maximum [Member]
Enable Units [Abstract]
Incentive distribution per unit										$ 0.330625
Enable Midstream Partners [Member] | Common Units [Member]
Enable Units [Abstract]
Limited partner interest units held		433,232,411								435,201,365		433,232,411
Enable Midstream Partners [Member] | Common Units [Member] | OGE [Member]
Enable Units [Abstract]
Limited partner interest units held		110,982,805								110,982,805		110,982,805
Enable Midstream Partners [Member] | Common Units [Member] | Public unitholders [Member]
Enable Units [Abstract]
Limited partner interest units held		88,392,983								90,361,937		88,392,983
Discontinued Operations, Disposed of by Means Other than Sale, Spinoff [Member] | Enable Midstream Partners [Member] | CERC Corp [Member]
Investment in unconsolidated affiliates - discontinued operations	[11]												2,472
Discontinued Operation, Income (Loss) from Discontinued Operation Disclosures [Abstract]
Discontinued Operation, Income (Loss) from Discontinued Operation, before Income Tax												$ 184	265
Income tax expense												46	104
Income (loss) from discontinued operations, net of tax												$ 138	$ 161
Enable GP, LLC [Member]
Enable Units [Abstract]
Management rights ownership percentage										50.00%
Incentive distribution right										40.00%
Enable GP, LLC [Member] | CenterPoint Energy [Member]
Enable Units [Abstract]
Management rights ownership percentage	[12],[13]									50.00%
Incentive distribution right	[13],[14]									40.00%
Enable GP, LLC [Member] | OGE [Member]
Enable Units [Abstract]
Management rights ownership percentage	[12]									50.00%
Incentive distribution right	[14]									60.00%

[1] Amounts have been recast to reflect discontinued operations in all periods presented.

[2] Represents the fair value of non-utility equity investments acquired in the Merger.

[3] Excludes the Enable Series A Preferred Units owned by CenterPoint Energy.

[4] Prior to the Internal Spin completed in September 2018, CenterPoint Energy’s investment in Enable’s common units, excluding the Enable Series A Preferred Units held directly by CenterPoint Energy, was held indirectly through CERC.

[5] Equity in earnings of unconsolidated affiliate includes CenterPoint Energy’s share of Enable earnings adjusted for the amortization of the basis difference of CenterPoint Energy’s original investment in Enable and its underlying equity in net assets of Enable. The basis difference is being amortized through the year 2048.

[6] Equity earnings for the year ended December 31, 2019 includes CenterPoint Energy’s share of Enable’s $86 million goodwill impairment recorded in the fourth quarter of 2019.

[7] Represents amounts billed for certain support services provided to Enable. Actual support services costs are recorded net of reimbursement.

[8] Prior to the Internal Spin completed in September 2018, distributions from Enable were received by CERC. After such date, distributions from Enable were received directly by CenterPoint Energy (through CNP Midstream).

[9] The carrying amount of the Enable Series A Preferred Units, reflected as Preferred units - unconsolidated affiliate on CenterPoint Energy’s Consolidated Balance Sheets, was $363 million as of both December 31, 2019 and 2018. No impairment charges or adjustment to carrying value were made as no observable price changes were identified in the current or prior reporting periods.

[10] Included in Non-utility costs of revenues, including natural gas on CenterPoint Energy’s and CERC’s respective Statements of Consolidated Income.

[11] On September 4, 2018, CERC completed the Internal Spin. For further information regarding the Internal Spin, see Note 11.

[12] As of December 31, 2019, Enable is controlled jointly by CenterPoint Energy and OGE. Sale of CenterPoint Energy’s or OGE’s ownership interests in Enable GP to a third party is subject to mutual rights of first offer and first refusal, and CenterPoint Energy is not permitted to dispose of less than all of its interest in Enable GP.

[13] Held indirectly through CNP Midstream.

[14] Enable is expected to pay a minimum quarterly distribution of $0.2875 per common unit on its outstanding common units to the extent it has sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to Enable GP and its affiliates, within 60 days after the end of each quarter. If cash distributions to Enable’s unitholders exceed $0.330625 per common unit in any quarter, Enable GP will receive increasing percentages or incentive distributions rights, up to 50%, of the cash Enable distributes in excess of that amount. In certain circumstances Enable GP will have the right to reset the minimum quarterly distribution and the target distribution levels at which the incentive distributions receive increasing percentages to higher levels based on Enable’s cash distributions at the time of the exercise of this reset election. To date, no incentive distributions have been made.

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Reportable Segments Financial Data (Details) - USD ($) $ in Millions		3 Months Ended												12 Months Ended
		Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018		Sep. 30, 2018		Jun. 30, 2018		Mar. 31, 2018		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Segment Reporting Information [Line Items]
Revenues		$ 3,230	$ 2,742	$ 2,798	$ 3,531	$ 3,036		$ 2,212		$ 2,186		$ 3,155		$ 12,301	$ 10,589	$ 9,614
Depreciation and Amortization														1,287	1,243	1,036
Operating Income (Loss)		302	392	287	245	167		226		187		251		1,226	831	1,136
Total Assets		35,439				27,009								35,439	27,009	22,736
Expenditures for Long-Lived Assets														2,587	1,720	1,494
Capital expenditures per Statements of Consolidated Cash Flows														2,506	1,651	1,426
Capitalized Fees Not Eliminated in Consolidation														162
Midstream Investments’ equity earnings, net														230	307	265
Regulatory Assets		2,129				2,044								2,129	2,044
Enable Midstream Partners [Member]
Segment Reporting Information [Line Items]
Midstream Investments’ equity earnings, net	[1],[2]													229	307	265
Electric Transmission & Distribution [Member]
Segment Reporting Information [Line Items]
Revenues	[3]													2,996	3,232	2,997
Depreciation and Amortization														648	917	724
Operating Income (Loss)														624	623	636
Expenditures for Long-Lived Assets														1,033	952	924
Electric Transmission & Distribution [Member] | Affiliates of NRG Energy, Inc. [Member]
Segment Reporting Information [Line Items]
Revenues														727	705	713
Electric Transmission & Distribution [Member] | Affiliates of Vistra Energy Corp. [Member]
Segment Reporting Information [Line Items]
Revenues														263	251	229
Indiana Electric Integrated [Member]
Segment Reporting Information [Line Items]
Revenues	[3]													523
Depreciation and Amortization														91
Operating Income (Loss)														90
Expenditures for Long-Lived Assets														183
Natural Gas Distribution [Member]
Segment Reporting Information [Line Items]
Revenues														3,643	2,931	2,606
Depreciation and Amortization														417	277	260
Operating Income (Loss)														408	266	348
Expenditures for Long-Lived Assets														1,098	638	523
Energy Services [Member]
Segment Reporting Information [Line Items]
Revenues														3,653	4,411	3,997
Depreciation and Amortization														16	16	19
Operating Income (Loss)														32	(47)	126
Expenditures for Long-Lived Assets														12	20	11
Infrastructure Services [Member]
Segment Reporting Information [Line Items]
Revenues	[4]													1,186
Depreciation and Amortization														50
Operating Income (Loss)														95
Expenditures for Long-Lived Assets														67
Midstream Investments [Member]
Segment Reporting Information [Line Items]
Revenues	[5]													0	0	0
Depreciation and Amortization	[5]													0	0	0
Operating Income (Loss)	[5]													0	0	0
Expenditures for Long-Lived Assets	[5]													0	0	0
Midstream Investments [Member] | Enable Midstream Partners [Member]
Segment Reporting Information [Line Items]
Midstream Investments’ equity earnings, net														229	307	265
Corporate and Other [Member]
Segment Reporting Information [Line Items]
Revenues														300	15	14
Depreciation and Amortization														65	33	33
Operating Income (Loss)														(23)	(11)	26
Expenditures for Long-Lived Assets														194	110	36
Operating Segments [Member] | Electric Transmission & Distribution [Member]
Segment Reporting Information [Line Items]
Total Assets		11,264				10,509								11,264	10,509	10,292
Operating Segments [Member] | Indiana Electric Integrated [Member]
Segment Reporting Information [Line Items]
Total Assets		3,168												3,168
Operating Segments [Member] | Natural Gas Distribution [Member]
Segment Reporting Information [Line Items]
Total Assets		13,903				6,956								13,903	6,956	6,608
Operating Segments [Member] | Energy Services [Member]
Segment Reporting Information [Line Items]
Total Assets		1,301				1,558								1,301	1,558	1,521
Operating Segments [Member] | Infrastructure Services [Member]
Segment Reporting Information [Line Items]
Total Assets		1,077												1,077
Operating Segments [Member] | Midstream Investments [Member]
Segment Reporting Information [Line Items]
Total Assets	[5]	2,473				2,482								2,473	2,482	2,472
Operating Segments [Member] | Corporate and Other [Member]
Segment Reporting Information [Line Items]
Total Assets	[6]	4,784				6,156								4,784	6,156	2,497
Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues														(173)	(146)	(85)
Total Assets		(2,531)				(652)								(2,531)	(652)	(654)
Intersegment Eliminations [Member] | Electric Transmission & Distribution [Member]
Segment Reporting Information [Line Items]
Revenues														0	0	0
Intersegment Eliminations [Member] | Natural Gas Distribution [Member]
Segment Reporting Information [Line Items]
Revenues														(40)	(36)	(33)
Intersegment Eliminations [Member] | Energy Services [Member]
Segment Reporting Information [Line Items]
Revenues														(129)	(110)	(52)
Intersegment Eliminations [Member] | Infrastructure Services [Member]
Segment Reporting Information [Line Items]
Revenues														(4)
Intersegment Eliminations [Member] | Midstream Investments [Member]
Segment Reporting Information [Line Items]
Revenues	[5]													0	0	0
Intersegment Eliminations [Member] | Corporate and Other [Member]
Segment Reporting Information [Line Items]
Revenues														0	0	0
Segment Reconciling Items [Member]
Segment Reporting Information [Line Items]
Expenditures for Long-Lived Assets														(81)	(69)	(68)
Houston Electric [Member]
Segment Reporting Information [Line Items]
Revenues		680	859	765	686	728		897		854		755		2,990	3,234	2,998
Depreciation and Amortization														648	917	724
Operating Income (Loss)		99	269	169	81	98		227		181		119		618	625	637
Total Assets		11,262				10,507								11,262	10,507
Capital expenditures per Statements of Consolidated Cash Flows														1,025	922	875
Regulatory Assets		915				1,124								915	1,124
Houston Electric [Member] | Electric Transmission & Distribution [Member] | Affiliates of NRG Energy, Inc. [Member]
Segment Reporting Information [Line Items]
Revenues														727	705	713
Houston Electric [Member] | Electric Transmission & Distribution [Member] | Affiliates of Vistra Energy Corp. [Member]
Segment Reporting Information [Line Items]
Revenues														263	251	229
CERC Corp [Member]
Segment Reporting Information [Line Items]
Revenues		1,734	1,126	1,342	2,368	2,303	[7]	1,312	[7]	1,328	[7]	2,400	[7]	6,570	7,343	6,603
Depreciation and Amortization														305	293	279
Operating Income (Loss)		73	$ 23	$ 58	$ 196	76	[7]	$ (7)	[7]	$ 22	[7]	$ 131	[7]	350	222	467
Total Assets	[8]	8,439				8,214								8,439	8,214	10,112
Expenditures for Long-Lived Assets														785	658	534
Capital expenditures per Statements of Consolidated Cash Flows														776	633	513
Capitalized Fees Not Eliminated in Consolidation														20
Regulatory Assets		203				258								203	258
CERC Corp [Member] | Natural Gas Distribution [Member]
Segment Reporting Information [Line Items]
Revenues														2,911	2,931	2,606
Depreciation and Amortization														289	277	260
Operating Income (Loss)														316	266	348
Expenditures for Long-Lived Assets														773	638	523
CERC Corp [Member] | Energy Services [Member]
Segment Reporting Information [Line Items]
Revenues														3,654	4,411	3,997
Depreciation and Amortization														16	16	19
Operating Income (Loss)														32	(47)	126
Expenditures for Long-Lived Assets														12	20	11
CERC Corp [Member] | Corporate and Other [Member]
Segment Reporting Information [Line Items]
Revenues														5	1	0
Depreciation and Amortization														0	0	0
Operating Income (Loss)														2	3	(7)
Expenditures for Long-Lived Assets														0	0	0
CERC Corp [Member] | Operating Segments [Member] | Natural Gas Distribution [Member]
Segment Reporting Information [Line Items]
Total Assets	[8]	7,497				6,956								7,497	6,956	6,608
CERC Corp [Member] | Operating Segments [Member] | Energy Services [Member]
Segment Reporting Information [Line Items]
Total Assets	[8]	1,301				1,558								1,301	1,558	1,521
CERC Corp [Member] | Operating Segments [Member] | Corporate and Other [Member]
Segment Reporting Information [Line Items]
Total Assets	[8]	149				66								149	66	70
CERC Corp [Member] | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues														(168)	(146)	(85)
Total Assets	[8]	(508)				(366)								(508)	(366)	(559)
CERC Corp [Member] | Intersegment Eliminations [Member] | Natural Gas Distribution [Member]
Segment Reporting Information [Line Items]
Revenues														(40)	(36)	(33)
CERC Corp [Member] | Intersegment Eliminations [Member] | Energy Services [Member]
Segment Reporting Information [Line Items]
Revenues														(128)	(110)	(52)
CERC Corp [Member] | Intersegment Eliminations [Member] | Corporate and Other [Member]
Segment Reporting Information [Line Items]
Revenues														0	0	0
CERC Corp [Member] | Segment Reconciling Items [Member]
Segment Reporting Information [Line Items]
Expenditures for Long-Lived Assets														(9)	(25)	(21)
Pension and Other Postretirement Plans Costs [Member] | Corporate and Other [Member]
Segment Reporting Information [Line Items]
Regulatory Assets		584				$ 665								584	$ 665	600
Cash and Cash Equivalents [Member]
Segment Reporting Information [Line Items]
Short-term Investments		$ 3,900												3,900
Discontinued Operations, Disposed of by Means Other than Sale, Spinoff [Member] | Enable Midstream Partners [Member] | CERC Corp [Member]
Segment Reporting Information [Line Items]
Revenues																0
Depreciation and Amortization																0
Operating Income (Loss)																0
Investment in unconsolidated affiliates - discontinued operations	[8]															2,472
Expenditures for Long-Lived Assets																$ 0
Infrastructure Services [Member]
Segment Reporting Information [Line Items]
Capitalized Fees Not Eliminated in Consolidation														$ 162

[1] Equity earnings for the year ended December 31, 2019 includes CenterPoint Energy’s share of Enable’s $86 million goodwill impairment recorded in the fourth quarter of 2019.

[2] Represents amounts billed for certain support services provided to Enable. Actual support services costs are recorded net of reimbursement.

[3] CenterPoint Energy’s Houston Electric T&D’s revenues from major customers are as follows:     Year Ended December 31,     2019   2018   2017     (in millions) Affiliates of NRG   $ 727
  $ 705
  $ 713
Affiliates of Vistra Energy Corp.   263
  251
  229

[4] Includes revenues not eliminated in consolidation for pipeline construction and repair services of $162 million capitalized by CenterPoint Energy’s NGD for the 11 months ended December 31, 2019. See Note 2(b).

[5] CenterPoint Energy’s Midstream Investments’ equity earnings, net are as follows:     Year Ended December 31,     2019   2018   2016     (in millions) Enable   $ 229
  $ 307
  $ 265

[6] Total assets included pension and other postemployment-related regulatory assets of $584 million, $665 million and $600 million as of December 31, 2019, 2018 and 2017, respectively. Additionally, total assets as of December 31, 2018 included $3.9 billion of temporary investments included in Cash and cash equivalents on CenterPoint Energy’s Consolidated Balance Sheets.

[7] Amounts have been recast to reflect discontinued operations in all periods presented.

[8] On September 4, 2018, CERC completed the Internal Spin. For further information regarding the Internal Spin, see Note 11.

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Related Party Transactions (Houston Electric and CERC) (Tables)

12 Months Ended

Dec. 31, 2019

Related Party Transactions [Abstract]

Schedule of Money Pool Investment and Borrowing [Table Text Block]

Houston Electric and CERC participate in a money pool through which they can borrow or invest on a short-term basis. Funding needs are aggregated and external borrowing or investing is based on the net cash position. The net funding requirements of the money pool are expected to be met with borrowings under CenterPoint Energy’s revolving credit facility or the sale of CenterPoint Energy’s commercial paper. 

The table below summarizes money pool activity:

	December 31, 2019						December 31, 2018
	Houston Electric			CERC			Houston Electric			CERC
	(in millions)
Money pool investments (borrowings) (1)	$	481		$	—		$	(1	)	$	114
Weighted average interest rate	1.98		%	1.98		%	2.42		%	2.42		%

(1)

Included in Accounts and notes receivable (payable)–affiliated companies in Houston Electric’s and CERC’s Consolidated Balance Sheets.

Schedule of Related Party Transactions [Table Text Block]

Houston Electric and CERC affiliate-related net interest income (expense) were as follows:

	Year Ended December 31,
	2019				2018				2017
	Houston Electric		CERC		Houston Electric		CERC		Houston Electric		CERC
	(in millions)
Interest income (expense), net (1)	$	18	$	4	$	1	$	—	$	2	$	—

(1) Interest income is included in Other, net and interest expense is included in Interest and other finance charges on Houston Electric’s and CERC’s respective Statements of Consolidated Income.

Amounts charged for these services are included primarily in Operation and maintenance expenses and amounts billed for natural gas sales are included in Non-utility revenues were as follows:

	Year Ended December 31,
	2019					2018					2017
	Houston Electric			CERC		Houston Electric			CERC		Houston Electric			CERC
	(in millions)
Corporate service charges	$	177		$	141	$	190		$	147	$	188		$	128
Net affiliate service charges (billings)	(8		)	8		(17		)	17		(9		)	9
Pipeline construction and repair service charges (1)	—			4		—			—		—			—
Natural gas sales (2)	—			1		—			—		—			—

(1) Represents charges from Infrastructure Services to CERC’s NGD for the period February 1, 2019 through December 31, 2019.

(2) Represents sales to Indiana Electric from CES for the period February 1, 2019 through December 31, 2019.

The table below presents transactions among Houston Electric, CERC and their parent, Utility Holding.

	Year Ended December 31,
	2019				2018				2017
	Houston Electric		CERC		Houston Electric		CERC		Houston Electric		CERC
	(in millions)
Cash dividends paid to parent	$	376	$	120	$	209	$	360	$	180	$	601
Cash contribution from parent	590		129		200		960		—		38
Capital distribution to parent associated with the Internal Spin (1)	—		28		—		1,473		—		—

(1)

The capital distribution in 2019 associated with the Internal Spin is a result of the return to accrual for the periods of CERC’s ownership during 2018.

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Earnings Per Share (CenterPoint Energy) (Tables)

12 Months Ended

Dec. 31, 2019

Earnings Per Share [Abstract]

Basic and Diluted Earnings Per Share [Table Text Block]

The following table reconciles numerators and denominators of CenterPoint Energy’s basic and diluted earnings per common share. Basic earnings per common share is determined by dividing Income available to common shareholders - basic by the Weighted average common shares outstanding - basic for the applicable period. Diluted earnings per common share is determined by the inclusion of potentially dilutive common stock equivalent shares that may occur if securities to issue Common Stock were exercised or converted into Common Stock.

	For the Year Ended December 31,
	2019		2018		2017
	(in millions, except per share and share amounts)
Numerator:
Income available to common shareholders - basic (1)	$	674	$	333	$	1,792
Add back: Series B Preferred Stock dividend (2)	—		—		—
Income available to common shareholders - diluted (1)	$	674	$	333	$	1,792
Denominator:
Weighted average common shares outstanding - basic	502,050,000		448,829,000		430,964,000
Plus: Incremental shares from assumed conversions:
Restricted stock (3)	3,107,000		3,636,000		3,344,000
Series B Preferred Stock (2)	—		—		—
Weighted average common shares outstanding - diluted	505,157,000		452,465,000		434,308,000
Earnings per common share:
Basic earnings per common share	$	1.34	$	0.74	$	4.16
Diluted earnings per common share	$	1.33	$	0.74	$	4.13

(1) Income available to common shareholders for the year ended December 31, 2019 includes net income from businesses acquired in the Merger of $190 million. See Note 4. Income available to common shareholders for the year ended December 31, 2017 includes a reduction in income tax expense of $1,113 million due to tax reform. See Note 15 for further discussion of the impacts of the TCJA.

(2) The potentially dilutive impact from Series B Preferred Stock applies the if-converted method in calculating diluted earnings per common share. Under this method, diluted earnings per common share is adjusted for the more dilutive effect of the Series B Preferred Stock as a result of either its accumulated dividend for the period in the numerator or the assumed-converted common share equivalent in the denominator. The computation of diluted earnings per common share outstanding for the year ended December 31, 2019 and December 31, 2018 excludes Series B Stock Dividends of $68 million and $17 million, respectively, and 34,354,000 and 8,885,000 potentially dilutive shares, respectively, because to include them would be anti-dilutive. However, these shares could be potentially dilutive in the future.

(3) The potentially dilutive impact from restricted stock awards applies the treasury stock method. Under this method, an increase in the average fair market value of Common Stock can result in a greater dilutive impact from these securities.

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Summary of Significant Accounting Policies (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Significant Accounting Policies [Line Items]
Capitalized Fees Not Eliminated in Consolidation		$ 162
Provision for doubtful accounts		16	$ 16	$ 14
Interest Expense [Member]
Significant Accounting Policies [Line Items]
Interest and AFUDC debt (1)	[1]	36	8	9
Other Income (Expense) [Member]
Significant Accounting Policies [Line Items]
AFUDC equity (2)	[2]	22	12	11
Houston Electric [Member]
Significant Accounting Policies [Line Items]
Provision for doubtful accounts		0	0	1
Houston Electric [Member] | Interest Expense [Member]
Significant Accounting Policies [Line Items]
Interest and AFUDC debt (1)	[1]	8	6	6
Houston Electric [Member] | Other Income (Expense) [Member]
Significant Accounting Policies [Line Items]
AFUDC equity (2)	[2]	15	10	10
CERC Corp [Member]
Significant Accounting Policies [Line Items]
Capitalized Fees Not Eliminated in Consolidation		20
Provision for doubtful accounts		12	16	13
CERC Corp [Member] | Interest Expense [Member]
Significant Accounting Policies [Line Items]
Interest and AFUDC debt (1)	[1]	3	2	2
CERC Corp [Member] | Other Income (Expense) [Member]
Significant Accounting Policies [Line Items]
AFUDC equity (2)	[2]	$ 3	$ 2	$ 1

[1] Included in Interest and other finance charges on the Registrants’ respective Statements of Consolidated Income.

[2] Included in Other Income (Expense) on the Registrants’ respective Statements of Consolidated Income.

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CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions		Dec. 31, 2019	Dec. 31, 2018
Current Assets:
Cash and cash equivalents	[1]	$ 241	$ 4,231
Investment in marketable securities		822	540
Accounts receivable		1,249	1,190
Accrued unbilled revenues		586	378
Natural gas and coal inventory		277	194
Materials and supplies		269	200
Non-trading derivative assets		136	100
Taxes receivable		106	0
Prepaid expense and other current assets		161	192
Total current assets		3,847	7,025
Property, Plant and Equipment, net		20,945	14,044
Other Assets:
Goodwill		5,164	867
Regulatory assets		2,117	1,967
Non-trading derivative assets		58	38
Investment in unconsolidated affiliates		2,408	2,482
Preferred units - unconsolidated affiliate		363	363
Intangible Assets, Net (Excluding Goodwill)		321	65
Other		216	158
Total other assets		10,647	5,940
Total Assets		35,439	27,009
Current Liabilities:
Current portion of VIE Securitization Bonds long-term debt		231	458
Indexed debt, net		19	24
Current portion of other long-term debt		618	0
Indexed debt securities derivative		893	601
Accounts payable		1,138	1,240
Taxes accrued		241	204
Interest accrued		158	121
Dividends accrued		0	187
Customer deposits		125	86
Non-trading derivative liabilities		51	126
Other		414	255
Total current liabilities		3,888	3,302
Other Liabilities:
Deferred income taxes, net		3,928	3,239
Non-trading derivative liabilities		29	5
Benefit obligations		754	796
Regulatory liabilities		3,474	2,525
Other		763	402
Total other liabilities		8,948	6,967
Long-term Debt:
VIE Securitization Bonds, net		746	977
Other long-term debt, net		13,498	7,705
Total long-term debt, net		14,244	8,682
Commitments and Contingencies (Note 16)
Shareholders’ Equity:
Cumulative preferred stock, $0.01 par value, 20,000,000 shares authorized		0	0
Common stock		5	5
Additional paid-in capital		6,080	6,072
Retained earnings		632	349
Accumulated other comprehensive income (loss)		(98)	(108)
Total shareholders’ equity		8,359	8,058
Total Liabilities and Shareholders’ Equity		35,439	27,009
Houston Electric [Member]
Current Assets:
Cash and cash equivalents	[2]	216	335
Accounts and notes receivable, net		238	283
Accounts and notes receivable—affiliated companies		523	20
Accrued unbilled revenues		117	110
Materials and supplies		147	135
Taxes receivable		0	5
Prepaid expense and other current assets		49	61
Total current assets		1,290	949
Property, Plant and Equipment, net		9,032	8,402
Other Assets:
Regulatory assets		915	1,124
Other		25	32
Total other assets		940	1,156
Total Assets		11,262	10,507
Current Liabilities:
Current portion of VIE Securitization Bonds long-term debt		231	458
Accounts payable		268	262
Accounts and notes payable—affiliated companies		76	78
Taxes accrued		123	115
Interest accrued		69	64
Non-trading derivative liabilities		0	24
Other		63	89
Total current liabilities		830	1,090
Other Liabilities:
Deferred income taxes, net		1,030	1,023
Benefit obligations		75	91
Regulatory liabilities		1,288	1,298
Other		69	65
Total other liabilities		2,462	2,477
Long-term Debt:
VIE Securitization Bonds, net		746	977
Other long-term debt, net		3,973	3,281
Total long-term debt, net		4,719	4,258
Commitments and Contingencies (Note 16)
Shareholders’ Equity:
Common stock		0	0
Additional paid-in capital		2,486	1,896
Retained earnings		780	800
Accumulated other comprehensive income (loss)		(15)	(14)
Total shareholders’ equity		3,251	2,682
Total Liabilities and Shareholders’ Equity		11,262	10,507
CERC Corp [Member]
Current Assets:
Cash and cash equivalents		2	14
Accounts receivable		693	894
Accounts and notes receivable—affiliated companies		10	120
Accrued unbilled revenues		257	268
Natural gas and coal inventory		202	194
Materials and supplies		71	65
Non-trading derivative assets		136	100
Prepaid expense and other current assets		44	115
Total current assets		1,415	1,770
Property, Plant and Equipment, net		5,836	5,226
Other Assets:
Goodwill		819	867
Regulatory assets		191	181
Non-trading derivative assets		58	38
Other		120	132
Total other assets		1,188	1,218
Total Assets	[3]	8,439	8,214
Current Liabilities:
Accounts payable		557	856
Accounts and notes payable—affiliated companies		48	50
Taxes accrued		84	82
Interest accrued		38	38
Customer deposits		76	75
Non-trading derivative liabilities		44	102
Other		191	137
Total current liabilities		1,038	1,340
Other Liabilities:
Deferred income taxes, net		470	406
Non-trading derivative liabilities		14	5
Benefit obligations		83	93
Regulatory liabilities		1,219	1,227
Other		428	329
Total other liabilities		2,214	2,060
Long-term Debt:
Total long-term debt, net		2,546	2,371
Commitments and Contingencies (Note 16)
Shareholders’ Equity:
Common stock		0	0
Additional paid-in capital		2,116	2,015
Retained earnings		515	423
Accumulated other comprehensive income (loss)		10	5
Total shareholders’ equity		2,641	2,443
Total Liabilities and Shareholders’ Equity		8,439	8,214
Series A Preferred Stock [Member]
Shareholders’ Equity:
Preferred Stock		790	790
Series B Preferred Stock [Member]
Shareholders’ Equity:
Preferred Stock		$ 950	$ 950

[1] CenterPoint Energy’s Cash and cash equivalents as of December 31, 2018 included $3.9 billion of temporary investments resulting from the Merger financings. CenterPoint Energy recorded interest income of $22 million, $28 million and $2 million for the years ended December 31, 2019, 2018 and 2017, respectively, in Other, net on CenterPoint Energy’s Statements of Consolidated Income. See Notes 13 and 14 for further details related to the Merger financings.

[2] Houston Electric’s Cash and cash equivalents as of December 31, 2019 and 2018 included $216 million and $335 million, respectively, of cash related to the Bond Companies. Houston Electric recorded interest income of $9 million, $4 million and $2 million for the years ended December 31, 2019, 2018 and 2017, respectively, in Other, net on Houston Electric’s Statement of Consolidated Income.

[3] On September 4, 2018, CERC completed the Internal Spin. For further information regarding the Internal Spin, see Note 11.

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STATEMENTS OF CONSOLIDATED INCOME - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Revenues:
Utility revenues		$ 7,162	$ 6,163	$ 5,603
Non-utility revenues		5,139	4,426	4,011
Total		12,301	10,589	9,614
Expenses:
Utility natural gas, fuel and purchased power		1,683	1,410	1,109
Non-utility cost of revenues, including natural gas	[1]	4,029	4,364	3,785
Operation and maintenance		3,550	2,335	2,157
Depreciation and amortization		1,287	1,243	1,036
Taxes other than income taxes		478	406	391
Goodwill impairment		48	0	0
Total		11,075	9,758	8,478
Operating Income		1,226	831	1,136
Other Income (Expense):
Gain (loss) on marketable securities		282	(22)	7
Gain (loss) on indexed debt securities		(292)	(232)	49
Interest and other finance charges		(528)	(361)	(313)
Interest on Securitization Bonds		(39)	(59)	(77)
Equity in earnings of unconsolidated affiliates, net		230	307	265
Other, net		50	50	(4)
Total		(297)	(317)	(73)
Income Before Income Taxes		929	514	1,063
Income tax expense (benefit)		138	146	(729)
Net Income		791	368	1,792
Preferred stock dividend requirement		117	35	0
Income Available to Common Shareholders	[2]	$ 674	$ 333	$ 1,792
Basic Earnings Per Common Share		$ 1.34	$ 0.74	$ 4.16
Diluted Earnings Per Common Share		$ 1.33	$ 0.74	$ 4.13
Weighted Average Common Shares Outstanding, Basic		502,050,000	448,829,000	430,964,000
Weighted Average Common Shares Outstanding, Diluted		505,157,000	452,465,000	434,308,000
Houston Electric [Member]
Revenues:
Total		$ 2,990	$ 3,234	$ 2,998
Expenses:
Operation and maintenance		1,477	1,452	1,402
Depreciation and amortization		648	917	724
Taxes other than income taxes		247	240	235
Total		2,372	2,609	2,361
Operating Income		618	625	637
Other Income (Expense):
Interest and other finance charges		(164)	(138)	(128)
Interest on Securitization Bonds		(39)	(59)	(77)
Other, net		21	(3)	(8)
Total		(182)	(200)	(213)
Income Before Income Taxes		436	425	424
Income tax expense (benefit)		80	89	(9)
Net Income		356	336	433
CERC Corp [Member]
Revenues:
Utility revenues		2,911	2,931	2,606
Non-utility revenues		3,659	4,412	3,997
Total		6,570	7,343	6,603
Expenses:
Utility natural gas, fuel and purchased power		1,312	1,410	1,109
Non-utility cost of revenues, including natural gas	[1]	3,503	4,364	3,785
Operation and maintenance		890	898	816
Depreciation and amortization		305	293	279
Taxes other than income taxes		162	156	147
Goodwill impairment		48	0	0
Total		6,220	7,121	6,136
Operating Income		350	222	467
Other Income (Expense):
Interest and other finance charges		(116)	(122)	(123)
Other, net		(8)	(8)	(25)
Total		(124)	(130)	(148)
Income Before Income Taxes		226	92	319
Income tax expense (benefit)		14	22	(265)
Income From Continuing Operations		212	70	584
Income from discontinued operations (net of tax expense of $-0-, $46, and $104, respectively)		0	138	161
Net Income		$ 212	$ 208	$ 745

[1] Income statement impact associated with cash flow hedge activity is related to gains and losses reclassified from Accumulated other comprehensive income into income. Amounts are immaterial for the years ended December 31, 2019, 2018 and 2017, respectively.

[2] Income available to common shareholders for the year ended December 31, 2019 includes net income from businesses acquired in the Merger of $190 million. See Note 4. Income available to common shareholders for the year ended December 31, 2017 includes a reduction in income tax expense of $1,113 million due to tax reform. See Note 15 for further discussion of the impacts of the TCJA.

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Regulatory Matters Houston Electric Base Rate Case (Details) - USD ($) $ in Millions	Jan. 23, 2020	Apr. 05, 2019	Dec. 31, 2019	Dec. 31, 2018
Public Utilities, General Disclosures [Line Items]
Non-current regulatory assets			$ 2,117	$ 1,967
CenterPoint Energy Houston Electric 2019 Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Revenue increase		$ 194
Rate base		$ 6,400
Debt capital structure		50.00%
Equity capital structure		50.00%
Return on equity		10.40%
Houston Electric Stipulation and Settlement Agreement [Member] | Public Utility Commission of Texas [Member]
Public Utilities, General Disclosures [Line Items]
General mortgage bonds used as collateral			68
Subsequent Event [Member] | Houston Electric Stipulation and Settlement Agreement [Member] | Public Utility Commission of Texas [Member]
Public Utilities, General Disclosures [Line Items]
Revenue increase	$ 13
Debt capital structure	57.50%
Equity capital structure	42.50%
Return on equity	9.40%
Unprotected Excess Deferred Income Tax	$ 105
Rate Case Expense [Member] | Houston Electric Stipulation and Settlement Agreement [Member]
Public Utilities, General Disclosures [Line Items]
Non-current regulatory assets			$ 12

XML

Revenue Recognition Summary of Contract Assets and Liabilities (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019 USD ($)
Change in Accounts Receivable [Roll Forward]
Opening balance as of December 31, 2018 (1)	$ 516	[1]
Closing balance as of December 31, 2019	800
Increase (Decrease) in Accounts Receivable	284
Change in Other Accrued Unbilled Revenues [Roll Forward]
Opening balance as of December 31, 2018 (1)	373	[1]
Closing balance as of December 31, 2019	579
Increase (Decrease) in Other Accrued Unbilled Revenues	206
Change in Contract Asset [Roll Forward]
Opening balance as of December 31, 2018 (1)	0	[1]
Closing balance as of December 31, 2019	61
Increase (Decrease) in Contract with Customer, Asset	61
Change in Contract Liability [Roll Forward]
Opening balance as of December 31, 2018 (1)	3	[1]
Closing balance as of December 31, 2019	34
Increase (Decrease) in Contract with Customer, Liability	31
Contract with Customer, Liability, Revenue Recognized	47
Houston Electric [Member]
Change in Accounts Receivable [Roll Forward]
Opening balance as of December 31, 2018 (1)	234
Closing balance as of December 31, 2019	210
Increase (Decrease) in Accounts Receivable	(24)
Change in Other Accrued Unbilled Revenues [Roll Forward]
Opening balance as of December 31, 2018 (1)	110
Closing balance as of December 31, 2019	117
Increase (Decrease) in Other Accrued Unbilled Revenues	7
Change in Contract Liability [Roll Forward]
Opening balance as of December 31, 2018 (1)	3
Closing balance as of December 31, 2019	3
Increase (Decrease) in Contract with Customer, Liability	0
Contract with Customer, Liability, Revenue Recognized	3
CERC Corp [Member]
Change in Accounts Receivable [Roll Forward]
Opening balance as of December 31, 2018 (1)	282
Closing balance as of December 31, 2019	282
Increase (Decrease) in Accounts Receivable	0
Change in Other Accrued Unbilled Revenues [Roll Forward]
Opening balance as of December 31, 2018 (1)	263
Closing balance as of December 31, 2019	250
Increase (Decrease) in Other Accrued Unbilled Revenues	$ (13)

[1] Opening balances related to Vectren are as of February 1, 2019, and are thus excluded from the opening balance as of December 31, 2018.

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Short Term Borrowings and Long Term Debt (Tables)

12 Months Ended

Dec. 31, 2019

Debt Disclosure [Abstract]

Schedule of Short-term Borrowings and Long-term Debt [Table Text Block]

	December 31, 2019					December 31, 2018
	Long-Term			Current (1)		Long-Term			Current (1)
	(in millions)
CenterPoint Energy:
ZENS due 2029 (2)	$	—		$	19	$	—		$	24
Senior notes 2.50% to 7.08% due 2020 to 2049 (3)	3,728			100		2,000			—
Variable rate term loans 2.275% to 2.56% due 2020 to 2021	1,000			500		—			—
First mortgage bonds 2.19% to 6.72% due 2022 to 2055 (4)	293			—		—			—
Pollution control bonds 5.125% due 2028 (5)	68			—		68			—
Commercial paper (6) (7)	1,901			—		—			—
Unamortized debt issuance costs	(22		)	—		(13		)	—
Unamortized discount and premium, net	(7		)	—		(2		)	—
Houston Electric debt (see details below)	4,719			231		4,258			458
CERC debt (see details below)	2,546			—		2,371			—
Other debt	18			18		—			—
Total CenterPoint Energy debt	$	14,244		$	868	$	8,682		$	482

	December 31, 2019					December 31, 2018
	Long-Term			Current (1)		Long-Term			Current (1)
	(in millions)
Houston Electric:
First mortgage bonds 9.15% due 2021	$	102		$	—	$	102		$	—
General mortgage bonds 1.85% to 6.95% due 2021 to 2049	3,912			—		3,212			—
Restoration Bond Company:
System restoration bonds 4.243% due 2022	134			62		197			59
Bond Company II:
Transition bonds 5.302% due 2019	—			—		—			208
Bond Company III:
Transition bonds 5.234% due 2020	—			29		29			56
Bond Company IV:
Transition bonds 2.161% to 3.028% due 2020 to 2024	613			140		753			135
Unamortized debt issuance costs	(27		)	—		(24		)	—
Unamortized discount and premium, net	(15		)	—		(11		)	—
Total Houston Electric debt	$	4,719		$	231	$	4,258		$	458

	December 31, 2019					December 31, 2018
	Long-Term			Current (1)		Long-Term			Current (1)
	(in millions)
CERC (8):
Senior notes 3.55% to 6.625% due 2021 to 2047	$	2,193		$	—	$	2,193		$	—
Commercial paper (6)	377			—		210			—
Unamortized debt issuance costs	(13		)	—		(15		)	—
Unamortized discount and premium, net	(11		)	—		(17		)	—
Total CERC debt	$	2,546		$	—	$	2,371		$	—

(1) Includes amounts due or exchangeable within one year of the date noted.

(2) CenterPoint Energy’s ZENS obligation is bifurcated into a debt component and an embedded derivative component. For additional information regarding ZENS, see Note 12(b). As ZENS are exchangeable for cash at any time at the option of the holders, these notes are classified as a current portion of long-term debt.

(3) Includes $532 million of senior notes issued by VUHI and $96 million of senior notes issued by Indiana Gas. The senior notes have stated interest rates that range from 3.72% to 7.08%. The senior notes issued by VUHI are guaranteed by SIGECO, Indiana Gas and VEDO. In connection with the Merger, two of CenterPoint Energy’s acquired wholly-owned subsidiaries, VUHI and VCC, made offers to prepay certain outstanding guaranteed senior notes as required pursuant to certain note purchase agreements previously entered into by VUHI and VCC. In turn, VUHI and VCC borrowed $568 million and $191 million, respectively, from CenterPoint Energy to fund note redemptions of senior notes effected pursuant to these prepayment offers. To fund these prepayments and payments of approximately $5 million of accrued interest, CenterPoint Energy issued approximately $764 million of commercial paper.

(4) The first mortgage bonds issued by SIGECO subject SIGECO’s properties to a lien under the related mortgage indenture.

(5) $68 million and $68 million of these series of debt were secured by general mortgage bonds of Houston Electric as of December 31, 2019 and 2018, respectively. These general mortgage bonds are not reflected in Houston Electric’s consolidated financial statements because of the contingent nature of the obligations.

(6) Classified as long-term debt because the termination date of the facility that backstops the commercial paper is more than one year from the date noted.

(7) Commercial paper issued by VUHI has maturities up to 30 days.

(8) Issued by CERC Corp.

Long-term Debt

Debt Retirements. During the year ended December 31, 2019, CenterPoint Energy retired the following debt instruments:

	Retirement Date	Debt Instrument	Aggregate Principal Amount		Interest Rate	Maturity Date
			(in millions)
CenterPoint Energy	December 2019	Guaranteed senior notes	$	3	3.33%	2022
CenterPoint Energy	December 2019	Guaranteed senior notes	6		4.53%	2025

In December 2019, VCC redeemed the aggregate principal amount of its guaranteed senior notes at a redemption price equal to 100% of the principal amount thereof, plus accrued and unpaid interest thereon to but excluding the redemption date, plus the make-whole premium.  The make-whole premium associated with the two redemptions was approximately $1 million and was included in Other Income, net on CenterPoint Energy’s Statements of Consolidated Income.

Debt Transactions. During the year ended December 31, 2019, the following debt instruments were issued or incurred:

	Issuance Date	Debt Instrument	Aggregate Principal Amount		Interest Rate as of December 31, 2019	Maturity Date
			(in millions)
Houston Electric	January 2019	General mortgage bonds	$	700	4.25%	2049
CenterPoint Energy (1)	February 2019	Variable rate term loan	25		2.275%	2020
CenterPoint Energy	May 2019	Variable rate term loan	1,000		2.56%	2021
CenterPoint Energy	August 2019	Unsecured senior notes	500		2.50%	2024
CenterPoint Energy	August 2019	Unsecured senior notes	400		2.95%	2030
CenterPoint Energy	August 2019	Unsecured senior notes	300		3.70%	2049

(1) Draw down by VCC on its variable rate term loan.

Schedule of Revolving Credit Facilities and Utilization of Such Facilities [Table Text Block]

The Registrants had the following revolving credit facilities as of December 31, 2019:

Execution  Date	Registrant	Size of Facility		Draw Rate of LIBOR plus (1)	Financial Covenant Limit on Debt for Borrowed Money to Capital Ratio		Debt for Borrowed Money to Capital Ratio as of December 31, 2019 (2)	Termination  Date
		(in millions)
March 3, 2016	CenterPoint Energy	$	3,300	1.500%	65%	(3)	59.0%	March 3, 2022
July 14, 2017	CenterPoint Energy (4)	400		1.125%	65%		51.6%	July 14, 2022
July 14, 2017	CenterPoint Energy (5)	200		1.250%	65%		58.0%	July 14, 2022
March 3, 2016	Houston Electric	300		1.125%	65%	(3)	50.2%	March 3, 2022
March 3, 2016	CERC	900		1.250%	65%		46.4%	March 3, 2022
	Total	$	5,100

(1) Based on credit ratings as of December 31, 2019.

(2) As defined in the revolving credit facility agreement, excluding Securitization Bonds.

(3) For CenterPoint Energy and Houston Electric, the financial covenant limit will temporarily increase from 65% to 70% if Houston Electric experiences damage from a natural disaster in its service territory and CenterPoint Energy certifies to the administrative agent that Houston Electric has incurred system restoration costs reasonably likely to exceed $100 million in a consecutive 12-month period, all or part of which Houston Electric intends to seek to recover through securitization financing. Such temporary increase in the financial covenant would be in effect from the date CenterPoint Energy delivers its certification until the earliest to occur of (i) the completion of the securitization financing, (ii) the first anniversary of CenterPoint Energy’s certification or (iii) the revocation of such certification.

(4) This credit facility was issued by VUHI, is guaranteed by SIGECO, Indiana Gas and VEDO and includes a $10 million swing line sublimit and a $20 million letter of credit sublimit. This credit facility backstops VUHI’s commercial paper program.

(5) This credit facility was issued by VCC, is guaranteed by Vectren and includes a $40 million swing line sublimit and an$80 million letter of credit sublimit.

The Registrants, as well as the subsidiaries of CenterPoint Energy discussed above, were in compliance with all financial debt covenants as of December 31, 2019.

As of December 31, 2019 and 2018, the Registrants had the following revolving credit facilities and utilization of such facilities:

	December 31, 2019								December 31, 2018
Registrant	Loans		Letters of Credit		Commercial Paper		Weighted Average Interest Rate		Loans		Letters of Credit		Commercial Paper		Weighted Average Interest Rate
	(in millions, except weighted average interest rate)
CenterPoint Energy (1)	$	—	$	6	$	1,633	1.95	%	$	—	$	6	$	—	—	%
CenterPoint Energy (2)	—		—		268		2.08	%	—		—		—		—	%
CenterPoint Energy (3)	—		—		—		—	%	—		—		—		—	%
Houston Electric	—		—		—		—	%	—		4		—		—	%
CERC	—		1		377		1.94	%	—		1		210		2.93	%
Total	$	—	$	7	$	2,278			$	—	$	11	$	210

(1) CenterPoint Energy’s outstanding commercial paper generally has maturities of 60 days or less.

(2) This credit facility was issued by VUHI and is guaranteed by SIGECO, Indiana Gas and VEDO.

(3) This credit facility was issued by VCC and is guaranteed by Vectren.

In January 2019, CenterPoint Energy issued the following commercial paper in connection with the closing of the Merger:

Registrant	Issuance Date	Debt Instrument	Aggregate Principal Amount		Weighted Average Interest Rate
			(in millions)
CenterPoint Energy (1) (2)	January 2019	Commercial paper	$	1,660	2.88%

(1) Proceeds from these commercial paper issuances were used to fund a portion of the Merger and to pay related fees and expenses and were contributed to Vectren for its payment of its stub period cash dividend, long-term incentive payments and to fund the repayment of indebtedness of Vectren subsidiaries redeemed at the option of the holder as a result of the closing of the Merger.

(2)

The commercial paper notes were issued at various times in January 2019 with maturities up to and including 90 days as of the time of issuance, and, prior to their use as described in connection with the closing of the Merger, the net proceeds of such issuances were invested in short-term investments.

Schedule of Maturities of Long-term Debt [Table Text Block]

Maturities.  As of December 31, 2019, maturities of long-term debt, capital leases and sinking fund requirements, excluding the ZENS obligation, are as follows:

	CenterPoint Energy (1)		Houston  Electric (1)		CERC		Securitization Bonds
	(in millions)
2020	$	831	$	231	$	—	$	231
2021	2,761		613		593		211
2022	3,302		519		376		219
2023	713		356		300		156
2024	1,184		162		—		162

(1)

These maturities include Securitization Bonds principal repayments on scheduled payment dates.

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Goodwill and Other Intangibles (CenterPoint Energy and CERC) (Tables)

12 Months Ended

Dec. 31, 2019

Goodwill and Intangible Assets Disclosure [Abstract]

Goodwill by Reportable Segments [Table Text Block]

CenterPoint Energy’s goodwill by reportable segment as of December 31, 2018 and changes in the carrying amount of goodwill as of December 31, 2019 are as follows:

	December 31, 2018		Additions (1)		Impairment		December 31, 2019
	(in millions)
Indiana Electric Integrated	$	—	$	1,121	$	—	$	1,121
Natural Gas Distribution	746		2,566		—		3,312
Energy Services (2)	110		—		48		62
Infrastructure Services	—		220		—		220
Corporate and Other	11		438		—		449
Total	$	867	$	4,345	$	48	$	5,164

(1) This represents the allocation of goodwill to reportable segments from the Merger, changes from preliminary amounts previously reported and includes the final determination of fair value for each reportable segment. See Note 4.

(2) Amount presented is net of the accumulated goodwill impairment charge of $252 million recorded in 2012. As of December 31, 2019, CenterPoint Energy and CERC identified a triggering event to perform an interim goodwill impairment test and recognized a goodwill impairment on their Energy Services reporting unit which is included in Goodwill impairment on CenterPoint Energy’s and CERC’s Consolidated Statements of Income.

CERC’s goodwill by reportable segment as of December 31, 2019 and December 31, 2018 is as follows:

	December 31, 2018		Impairment		December 31, 2019
			(in millions)
Natural Gas Distribution	$	746	$	—	$	746
Energy Services (1)	110		48		62
Corporate and Other	11		—		11
Total	$	867	$	48	$	819

(1)

Amount presented is net of the accumulated goodwill impairment charge of $252 million recorded in 2012.

Schedule of Finite-Lived Intangible Assets [Table Text Block]

The tables below present information on CERC’s other intangible assets recorded in Other non-current assets on CERC’s Consolidated Balance Sheets and the related amortization expense included in Depreciation and amortization on CERC’s Statements of Consolidated Income.

	December 31, 2019							December 31, 2018
	Gross Carrying Amount		Accumulated Amortization			Net Balance		Gross Carrying Amount		Accumulated Amortization			Net Balance
	(in millions)
Customer relationships	$	86	$	(32	)	$	54	$	86	$	(27	)	$	59
Covenants not to compete	4		(4		)	—		4		(3		)	1
Other	16		(14		)	2		16		(11		)	5
Total	$	106	$	(50	)	$	56	$	106	$	(41	)	$	65

The tables below present information on CenterPoint Energy’s other intangible assets recorded in Intangible assets, net on the Consolidated Balance Sheets and the related amortization expense included in Depreciation and amortization on CenterPoint Energy’s Statements of Consolidated Income, unless otherwise indicated.

	December 31, 2019							December 31, 2018
	Gross Carrying Amount		Accumulated Amortization			Net Balance		Gross Carrying Amount		Accumulated Amortization			Net Balance
	(in millions)
Customer relationships (1)	$	286	$	(43	)	$	243	$	86	$	(27	)	$	59
Covenants not to compete	4		(4		)	—		4		(3		)	1
Trade names (1)	58		(5		)	53		—		—			—
Construction backlog (1) (2)	27		(23		)	4		—		—			—
Operation and maintenance       agreements (1) (2)	12		(1		)	11		—		—			—
Other (1)	24		(14		)	10		16		(11		)	5
Total	$	411	$	(90	)	$	321	$	106	$	(41	)	$	65

(1) The fair value of intangible assets acquired through acquisitions has been finalized. See Note 4.

(2)

Amortization expense related to the operation and maintenance agreements and construction backlog is included in Non-utility cost of revenues, including natural gas on CenterPoint Energy’s Statements of Consolidated Income.

Finite-lived Intangible Assets Amortization Expense [Table Text Block]

	Year Ended December 31,
	2019		2018		2017
	(in millions)
Amortization expense of intangible assets recorded in    Depreciation and amortization (1) (2)	$	25	$	10	$	13
Amortization expense of intangible assets recorded in Non-utility cost of revenues, including natural gas (2)	24		—		—

(1) Includes $17 million for the year ended December 31, 2019 of amortization expense related to intangibles acquired in the Merger.

(2)

The fair value of intangible assets, and related amortization assumptions, acquired through acquisitions during the year ended December 31, 2019, has been finalized. See Note 4.

	Year Ended December 31,
	2019		2018		2017
	(in millions)
Amortization expense of intangible assets recorded in    Depreciation and amortization	$	9	$	10	$	13

Schedule of Finite-Lived Intangible Assets, Future Amortization Expense [Table Text Block]

CenterPoint Energy and CERC estimate that amortization expense of intangible assets with finite lives for the next five years will be as follows:

	Amortization Expense
	CenterPoint Energy		CERC
	(in millions)
2020	$	29	$	6
2021	25		6
2022	25		6
2023	24		5
2024	22		5

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Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2019

Fair Value Disclosures [Abstract]

Fair Value, Assets Measured on a Recurring Basis [Table Text Block]

The following tables present information about the Registrants’ assets and liabilities (including derivatives that are presented net) measured at fair value on a recurring basis as of December 31, 2019 and December 31, 2018, and indicate the fair value hierarchy of the valuation techniques utilized by the Registrants to determine such fair value.

CenterPoint Energy

	December 31, 2019											December 31, 2018
	Level 1		Level 2		Level 3		Netting (1)			Total		Level 1		Level 2		Level 3		Netting (1)			Total
Assets	(in millions)
Corporate equities	$	825	$	—	$	—	$	—		$	825	$	542	$	—	$	—	$	—		$	542
Investments, including money market funds (2)	49		—		—		—			49		66		—		—		—			66
Natural gas derivatives (3)(4)	—		250		42		(98		)	194		—		173		47		(82		)	138
Hedged portion of natural gas inventory	—		—		—		—			—		1		—		—		—			1
Total assets	$	874	$	250	$	42	$	(98	)	$	1,068	$	609	$	173	$	47	$	(82	)	$	747

	December 31, 2019											December 31, 2018
	Level 1		Level 2		Level 3		Netting (1)			Total		Level 1		Level 2		Level 3		Netting (1)			Total
Liabilities
Indexed debt securities derivative	$	—	$	893	$	—	$	—		$	893	$	—	$	601	$	—	$	—		$	601
Interest rate derivatives	—		10		—		—			10		24		—		—		—			24
Natural gas derivatives (3)(4)	—		217		24		(161		)	80		—		191		17		(101		)	107
Hedged portion of natural gas inventory	13		—		—		—			13		—		—		—		—			—
Total liabilities	$	13	$	1,120	$	24	$	(161	)	$	996	$	24	$	792	$	17	$	(101	)	$	732

Houston Electric

	December 31, 2019										December 31, 2018
	Level 1		Level 2		Level 3		Netting		Total		Level 1		Level 2		Level 3		Netting		Total
Assets	(in millions)
Investments, including money market funds (2)	$	32	$	—	$	—	$	—	$	32	$	48	$	—	$	—	$	—	$	48
Total assets	$	32	$	—	$	—	$	—	$	32	$	48	$	—	$	—	$	—	$	48
Liabilities
Interest rate derivatives	$	—	$	—	$	—	$	—	$	—	$	24	$	—	$	—	$	—	$	24
Total liabilities	$	—	$	—	$	—	$	—	$	—	$	24	$	—	$	—	$	—	$	24

CERC

	December 31, 2019											December 31, 2018
	Level 1		Level 2		Level 3		Netting (1)			Total		Level 1		Level 2		Level 3		Netting (1)			Total
Assets	(in millions)
Corporate equities	$	2	$	—	$	—	$	—		$	2	$	2	$	—	$	—	$	—		$	2
Investments, including money market funds (2)	11		—		—		—			11		11		—		—		—			11
Natural gas derivatives (3)(4)	—		250		42		(98		)	194		—		173		47		(82		)	138
Hedged portion of natural gas inventory	—		—		—		—			—		1		—		—		—			1
Total assets	$	13	$	250	$	42	$	(98	)	$	207	$	14	$	173	$	47	$	(82	)	$	152
Liabilities
Natural gas derivatives (3)(4)	$	—	$	195	$	24	$	(161	)	$	58	$	—	$	191	$	17	$	(101	)	$	107
Hedged portion of natural gas inventory	13		—		—		—			13		—		—		—		—			—
Total liabilities	$	13	$	195	$	24	$	(161	)	$	71	$	—	$	191	$	17	$	(101	)	$	107

(1) Amounts represent the impact of legally enforceable master netting arrangements that allow CenterPoint Energy and CERC to settle positive and negative positions and also include cash collateral posted with the same counterparties as follows:

	December 31, 2019				December 31, 2018
	CenterPoint Energy		CERC		CenterPoint Energy		CERC
	(in millions)
Cash collateral posted with the same counterparties	$	63	$	63	$	19	$	19

(2) Amounts are included in Prepaid and Other Current Assets and Other Assets in the Consolidated Balance Sheets.

(3) Natural gas derivatives include no material amounts related to physical forward transactions with Enable.

(4) Level 1 natural gas derivatives include exchange-traded derivatives cleared by the CME, which deems that financial instruments cleared by the CME are settled daily in connection with posted cash payments. As a result of this exchange rule, CME-related derivatives are considered to have no fair value at the balance sheet date for financial reporting purposes, and are presented in Level 1 net of posted cash; however, the derivatives remain outstanding and subject to future commodity price fluctuations until they are settled in accordance with their contractual terms. Derivative transactions cleared on exchanges other than the CME (e.g., the Intercontinental Exchange or ICE) continue to be reported on a gross basis.

Assets and Liabilities Measured at Fair Value on a Recurring Basis Using Significant Unobservable Inputs [Table Text Block]

The following table presents additional information about assets or liabilities, including derivatives that are measured at fair value on a recurring basis for which CenterPoint Energy and CERC have utilized Level 3 inputs to determine fair value:

	Year Ended December 31,
	2019						2018						2017
	CenterPoint Energy			CERC			CenterPoint Energy			CERC			CenterPoint Energy			CERC
	(in millions)
Beginning balance	$	30		$	30		$	(622	)	$	46		$	(704	)	$	13
Total gains	17			17			30			30			96			47
Total settlements	(22		)	(22		)	(39		)	(39		)	(11		)	(11		)
Transfers into Level 3	(1		)	(1		)	5			5			14			14
Transfers out of Level 3 (1)	(6		)	(6		)	656			(12		)	(17		)	(17		)
Ending balance (2)	$	18		$	18		$	30		$	30		$	(622	)	$	46
The amount of total gains for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the reporting date:
	$	12		$	12		$	18		$	18		$	87		$	38

(1) During 2018, CenterPoint Energy transferred its indexed debt securities derivative from Level 3 to Level 2 to reflect changes in the significance of the unobservable inputs used in the valuation.

(2)

CenterPoint Energy and CERC did not have significant Level 3 purchases or sales during any of the years ended December 31, 2019, 2018 or 2017.

Estimated Fair Value of Financial Instruments, Debt Instruments [Table Text Block]

The fair values of cash and cash equivalents, investments in debt and equity securities classified as “trading” and short-term borrowings are estimated to be approximately equivalent to carrying amounts and have been excluded from the table below. The carrying amounts of non-trading derivative assets and liabilities and CenterPoint Energy’s ZENS indexed debt securities derivative are stated at fair value and are excluded from the table below. The fair value of each debt instrument is determined by multiplying the principal amount of each debt instrument by a combination of historical trading prices and comparable issue data. These liabilities, which are not measured at fair value in the Registrants’ Consolidated Balance Sheets, but for which the fair value is disclosed, would be classified as Level 2 in the fair value hierarchy.

	December 31, 2019						December 31, 2018
	CenterPoint Energy (1)		Houston Electric (1)		CERC		CenterPoint Energy (1)		Houston Electric (1)		CERC
Long-term debt, including current maturities	(in millions)
Carrying amount	$	15,093	$	4,950	$	2,546	$	9,140	$	4,717	$	2,371
Fair value	16,067		5,457		2,803		9,308		4,770		2,488

(1) Includes Securitization Bond debt.

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Income Taxes

12 Months Ended

Dec. 31, 2019

Income Tax Disclosure [Abstract]

Income Taxes [Text Block]

Income Taxes

The components of the Registrant’ income tax expense (benefit) were as follows:

	Year Ended December 31,
	2019			2018			2017
	(in millions)
CenterPoint Energy
Current income tax expense:
Federal	$	48		$	89		$	32
State	21			9			9
Total current expense	69			98			41
Deferred income tax expense (benefit):
Federal	74			(25		)	(806		)
State	(5		)	73			36
Total deferred expense (benefit)	69			48			(770		)
Total income tax expense (benefit)	$	138		$	146		$	(729	)
Houston Electric
Current income tax expense:
Federal	$	84		$	109		$	70
State	20			18			19
Total current expense	104			127			89
Deferred income tax benefit:
Federal	(24		)	(38		)	(98		)
Total deferred benefit	(24		)	(38		)	(98		)
Total income tax expense (benefit)	$	80		$	89		$	(9	)
CERC - Continuing Operations
Current income tax expense (benefit):
Federal	$	—		$	(9	)	$	(31	)
State	7			—			(10		)
Total current expense (benefit)	7			(9		)	(41		)
Deferred income tax expense (benefit):
Federal	39			10			(249		)
State	(32		)	21			25
Total deferred expense (benefit)	7			31			(224		)
Total income tax expense (benefit)	$	14		$	22		$	(265	)
CERC - Discontinued Operations
Current income tax expense (benefit):
Federal	$	—		$	9		$	31
State	—			4			11
Total current expense (benefit)	—			13			42
Deferred income tax expense:
Federal	—			29			56
State	—			4			6
Total deferred expense	—			33			62
Total income tax expense	$	—		$	46		$	104

A reconciliation of income tax expense (benefit) using the federal statutory income tax rate to the actual income tax expense and resulting effective income tax rate is as follows:

	Year Ended December 31,
	2019			2018			2017
	(in millions)
CenterPoint Energy (1) (2) (3)
Income before income taxes	$	929		$	514		$	1,063
Federal statutory income tax rate	21		%	21		%	35		%
Expected federal income tax expense	195			108			372
Increase (decrease) in tax expense resulting from:
State income tax expense, net of federal income tax	36			22			26
State valuation allowance, net of federal income tax	(4		)	11			3
State law change, net of federal income tax	(21		)	32			—
Federal income tax rate reduction	—			—			(1,113		)
Excess deferred income tax amortization	(55		)	(24		)	—
Other, net	(13		)	(3		)	(17		)
Total	(57		)	38			(1,101		)
Total income tax expense (benefit)	$	138		$	146		$	(729	)
Effective tax rate	15		%	28		%	(69		)%
Houston Electric (4) (5) (6)
Income before income taxes	$	436		$	425		$	424
Federal statutory income tax rate	21		%	21		%	35		%
Expected federal income tax expense	92			89			148
Increase (decrease) in tax expense resulting from:
State income tax expense, net of federal income tax	16			14			12
Federal income tax rate reduction	—			—			(158		)
Excess deferred income tax amortization	(21		)	(9		)	—
Other, net	(7		)	(5		)	(11		)
Total	(12		)	—			(157		)
Total income tax expense (benefit)	$	80		$	89		$	(9	)
Effective tax rate	18		%	21		%	(2		)%
CERC - Continuing Operations (7) (8) (9)
Income before income taxes	$	226		$	92		$	319
Federal statutory income tax rate	21		%	21		%	35		%
Expected federal income tax expense	47			19			112
Increase (decrease) in tax expense resulting from:
State income tax expense, net of federal income tax	(12		)	5			6
State law change, net of federal income tax	(4		)	—			—
State valuation allowance, net of federal income tax	(4		)	11			3
Federal income tax rate reduction	—			—			(396		)
Goodwill impairment	8			—			—
Excess deferred income tax amortization	(18		)	(15		)	—
Tax basis balance sheet adjustment	—			—			11
Other, net	(3		)	2			(1		)
Total	(33		)	3			(377		)
Total income tax expense (benefit)	$	14		$	22		$	(265	)
Effective tax rate	6		%	24		%	(83		)%

	Year Ended December 31,
	2019			2018			2017
	(in millions)
CERC - Discontinued Operations (9)
Income before income taxes	$	—		$	184		$	265
Federal statutory income tax rate	—		%	21		%	35		%
Expected federal income tax expense	—			39			93
Increase in tax expense resulting from:
State income tax expense, net of federal income tax	—			7			11
Total	—			7			11
Total income tax expense	$	—		$	46		$	104
Effective tax rate	—		%	25		%	39		%

(1) Recognized a $55 million benefit for the amortization of the net regulatory EDIT liability as decreed by regulators in certain jurisdictions, a $21 million net benefit for the impact of state law changes that resulted in the remeasurement of state deferred taxes in those jurisdictions, and $4 million net benefit for the reduction in valuation allowances on certain state net operating losses that are now expected to be realized.

(2) Recognized a $32 million deferred tax expense due to state law changes that resulted in remeasurement of state deferred taxes in those jurisdictions. Also recorded an additional $11 million valuation allowance on certain state net operating loss deferred tax assets that are no longer expected to be utilized prior to expiration after the Internal Spin. These items are partially offset by $24 million of amortization of the net regulatory EDIT liability as decreed by regulators in certain jurisdictions beginning in 2018.

(3) Recognized a $1.1 billion deferred tax benefit from the remeasurement of CenterPoint Energy’s ADFIT liability as a result of the enactment of the TCJA on December 22, 2017, which reduced the U.S. corporate income tax rate from 35% to 21%.

(4) Recognized $21 million of amortization of the net regulatory EDIT liability as decreed by regulators.

(5) Recognized $9 million of amortization of the net regulatory EDIT liability as decreed by regulators in certain jurisdictions beginning in 2018.

(6) Recognized a $158 million deferred tax benefit from the remeasurement of Houston Electric’s ADFIT liability as a result of the enactment of the TCJA on December 22, 2017, which reduced the U.S. corporate income tax rate from 35% to 21%.

(7) Recognized $18 million benefit for the amortization of the net regulatory EDIT liability as decreed by regulators in certain jurisdictions, $4 million net benefit for the impact of state law changes that resulted in the remeasurement of state deferred taxes in those jurisdictions and $4 million net benefit for the reduction in valuation allowances on certain state net operating losses that are now expected to be realized.

(8) Recorded an additional $11 million valuation allowance on certain state net operating loss deferred tax assets that are no longer expected to be utilized prior to expiration after the Internal Spin. This item is partially offset by $15 million of amortization of the net regulatory EDIT liability in certain jurisdictions as decreed by regulators beginning in 2018.

(9) Recognized a $396 million deferred tax benefit from the remeasurement of CERC’s ADFIT liability as a result of the enactment of the TCJA on December 22, 2017, which reduced the U.S. corporate income tax rate from 35% to 21%. ASC 740 requires tax impacts of changes in tax laws or rates be reported in continuing operations. Therefore, CERC’s federal income tax benefit generated by the remeasurement of the ADFIT liability for Enable during 2017 and state law changes during 2016 associated with its investment in Enable are reported in continuing operations on CERC’s Statements of Consolidated Income. The ADFIT liability associated with CERC’s investment in Enable is reported as discontinued operations on CERC’s Consolidated Balance Sheets. 

The tax effects of temporary differences that give rise to significant portions of deferred tax assets and liabilities were as follows:

	December 31,
	2019			2018
	(in millions)
CenterPoint Energy
Deferred tax assets:
Benefits and compensation	$	152		$	160
Regulatory liabilities	447			356
Loss and credit carryforwards	111			84
Asset retirement obligations	89			62
Indexed debt securities derivative	34			—
Other	40			29
Valuation allowance	(25		)	(18		)
Total deferred tax assets	848			673
Deferred tax liabilities:
Property, plant and equipment	2,656			1,894
Investment in unconsolidated affiliates	1,010			987
Regulatory assets	344			395
Investment in marketable securities and indexed debt	586			478
Indexed debt securities derivative	—			27
Other	180			131
Total deferred tax liabilities	4,776			3,912
Net deferred tax liabilities	$	3,928		$	3,239
Houston Electric
Deferred tax assets:
Regulatory liabilities	$	195		$	205
Benefits and compensation	14			17
Asset retirement obligations	9			7
Other	7			12
Total deferred tax assets	225			241
Deferred tax liabilities:
Property, plant and equipment	1,129			1,087
Regulatory assets	126			177
Total deferred tax liabilities	1,255			1,264
Net deferred tax liabilities	$	1,030		$	1,023
CERC - Continuing Operations
Deferred tax assets:
Benefits and compensation	$	24		$	27
Regulatory liabilities	144			150
Loss and credit carryforwards	183			259
Asset retirement obligations	80			54
Other	23			20
Valuation allowance	(15		)	(18		)
Total deferred tax assets	439			492
Deferred tax liabilities:
Property, plant and equipment	821			773
Regulatory assets	45			41
Other	43			84
Total deferred tax liabilities	909			898
Net deferred tax liabilities	$	470		$	406

Merger with Vectren. On Merger Date, pursuant to the Merger Agreement, CenterPoint Energy consummated the Merger and acquired Vectren for approximately $6 billion in cash. On the Merger Date, Vectren became a wholly-owned subsidiary of CenterPoint Energy which triggered an ownership change under Section 382 of the Code. Under this Code section, future utilization of acquired net operating loss carry forwards and other tax attributes can be limited. On the Merger Date, Vectren estimated $177 million and $60 million of federal net operating loss and of charitable contribution carryforwards, respectively, the utilization of which is not expected to be limited under Section 382.

Tax Attribute Carryforwards and Valuation Allowance.  CenterPoint Energy has no federal net operating loss carryforwards as of December 31, 2019. Also, CenterPoint Energy has $26 million of federal charitable contribution carryforwards, which have a five-year carryover period. As of December 31, 2019, CenterPoint Energy had $699 million of state net operating loss carryforwards that expire between 2020 and 2039 and $21 million of state tax credits that do not expire. CenterPoint Energy reported a valuation allowance of $25 million because it is more likely than not that the benefit from certain state net operating loss carryforwards will not be realized.

CERC has $618 million of federal net operating loss carryforwards which have an indefinite carryforward period. CERC has $691 million of state net operating loss carryforwards which expire between 2020 and 2039 and $17 million of state tax credits which do not expire. CERC reported a valuation allowance of $15 million since it is more likely than not that the benefit from certain state net operating loss carryforwards will not be realized.

A reconciliation of CenterPoint Energy’s beginning and ending balance of unrecognized tax benefits, excluding interest and penalties, for 2019 is as follows:

	Year Ended December 31, 2019
	(in millions)
Balance, beginning of year	$	—
Unrecognized tax benefits assumed through the Merger	9
Decreases related to tax positions of prior years	(1		)
Balance, end of year	$	8

CenterPoint Energy had no unrecognized tax benefits for 2018 and 2017.

During the year ended December 31, 2019, CenterPoint Energy acquired $9 million of unrecognized tax benefits in connection with the Merger. Included in the balance of uncertain tax positions as of December 31, 2019 are $3 million of tax benefits that, if recognized, would affect the effective tax rate. The above table does not include an immaterial amount of accrued interest as of December 31, 2019. The Registrants recognize interest accrued related to unrecognized tax benefits and penalties as income tax expense. The Registrants believe that it is reasonably possible that a decrease of up to $5 million in unrecognized tax benefits may occur by the end of 2020 as a result of a lapse of statutes on older exposures and/or the filing of applications for accounting method changes. CenterPoint Energy’s net unrecognized tax benefits, including penalties and interest, were $9 million as of December 31, 2019 and are included in other non-current liabilities in the Consolidated Financial Statements.

Tax Audits and Settlements. Tax years through 2017 have been audited and settled with the IRS for CenterPoint Energy. For the 2018 and 2019 tax years, the Registrants are participants in the IRS’s Compliance Assurance Process. Legacy Vectren is not currently under audit with the IRS, and the 2017-2019 tax years are still open.

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Unconsolidated Affiliate (CenterPoint Energy and CERC)

12 Months Ended

Dec. 31, 2019

Equity Method Investments and Joint Ventures [Abstract]

Unconsolidated Affiliate (CenterPoint Energy and CERC) [Text Block]

Unconsolidated Affiliates (CenterPoint Energy and CERC)

CenterPoint Energy has the ability to significantly influence the operating and financial policies of Enable, a publicly traded MLP, and, accordingly, accounts for its investment in Enable’s common units using the equity method of accounting. Enable is considered to be a VIE because the power to direct the activities that most significantly impact Enable’s economic performance does not reside with the holders of equity investment at risk. However, CenterPoint Energy is not considered the primary beneficiary of Enable since it does not have the power to direct the activities of Enable that are considered most significant to the economic performance of Enable. As of December 31, 2019, CenterPoint Energy’s maximum exposure to loss related to Enable is limited to its investment in unconsolidated affiliate, its investment in Enable Series A Preferred Units and outstanding current accounts receivable from Enable.

Investment in Unconsolidated Affiliates (CenterPoint Energy):

	December 31, 2019		December 31, 2018
	(in millions)
Enable	$	2,406	$	2,482
Other (1)	2		—
Total	$	2,408	$	2,482

(1) Represents the fair value of non-utility equity investments acquired in the Merger.

CenterPoint Energy evaluates its equity method investments for impairment when factors indicate that a decrease in value of its investment has occurred and the carrying amount of its investment may not be recoverable. An impairment loss is recognized in earnings when an impairment is deemed to be other than temporary. As of December 31, 2019, CenterPoint Energy’s investment in Enable is $10.29 per unit and Enable’s common unit price closed at $10.03 per unit (approximately $61 million below carrying value). Based on an analysis of its investment in Enable as of December 31, 2019, CenterPoint Energy believes that the decline in the value of its investment is temporary, and that the carrying value of its investment of $2.4 billion will be recovered.

Equity in Earnings of Unconsolidated Affiliates, net (CenterPoint Energy):

	Year Ended December 31,
	2019		2018		2017
	(in millions)
Enable (1)	$	229	$	307	$	265
Other	1		—		—
Total	$	230	$	307	$	265

(1) Equity earnings for the year ended December 31, 2019 includes CenterPoint Energy’s share of Enable’s $86 million goodwill impairment recorded in the fourth quarter of 2019.

Limited Partner Interest and Units Held in Enable (CenterPoint Energy):

	As of December 31,
	2019				2018
	Limited Partner Interest (1)		Common Units	Enable Series A Preferred Units (2)	Limited Partner Interest (1)		Common Units	Enable Series A Preferred Units (2)
CenterPoint Energy (3)	53.7	%	233,856,623	14,520,000	54.0	%	233,856,623	14,520,000
OGE	25.5	%	110,982,805	—	25.6	%	110,982,805	—
Public unitholders	20.8	%	90,361,937	—	20.4	%	88,392,983	—
Total Units Outstanding	100.0	%	435,201,365	14,520,000	100.0	%	433,232,411	14,520,000

(1) Excludes the Enable Series A Preferred Units owned by CenterPoint Energy.

(2) The carrying amount of the Enable Series A Preferred Units, reflected as Preferred units - unconsolidated affiliate on CenterPoint Energy’s Consolidated Balance Sheets, was $363 million as of both December 31, 2019 and 2018. No

impairment charges or adjustment to carrying value were made as no observable price changes were identified in the current or prior reporting periods.

(3) Prior to the Internal Spin completed in September 2018, CenterPoint Energy’s investment in Enable’s common units, excluding the Enable Series A Preferred Units held directly by CenterPoint Energy, was held indirectly through CERC.

Generally, sales to any person or entity (including a series of sales to the same person or entity) of more than 5% of the aggregate of the common units CenterPoint Energy owns in Enable or sales to any person or entity (including a series of sales to the same person or entity) by OGE of more than 5% of the aggregate of the common units it owns in Enable are subject to mutual rights of first offer and first refusal set forth in Enable’s Agreement of Limited Partnership.

Interests Held in Enable GP (CenterPoint Energy):

CenterPoint Energy and OGE held the following interests in Enable GP as of both December 31, 2019 and 2018:

	Management  Rights (1)		Incentive Distribution Rights (2)
CenterPoint Energy (3)	50	%	40	%
OGE	50	%	60	%

(1) As of December 31, 2019, Enable is controlled jointly by CenterPoint Energy and OGE. Sale of CenterPoint Energy’s or OGE’s ownership interests in Enable GP to a third party is subject to mutual rights of first offer and first refusal, and CenterPoint Energy is not permitted to dispose of less than all of its interest in Enable GP.

(2) Enable is expected to pay a minimum quarterly distribution of $0.2875 per common unit on its outstanding common units to the extent it has sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to Enable GP and its affiliates, within 60 days after the end of each quarter. If cash distributions to Enable’s unitholders exceed $0.330625 per common unit in any quarter, Enable GP will receive increasing percentages or incentive distributions rights, up to 50%, of the cash Enable distributes in excess of that amount. In certain circumstances Enable GP will have the right to reset the minimum quarterly distribution and the target distribution levels at which the incentive distributions receive increasing percentages to higher levels based on Enable’s cash distributions at the time of the exercise of this reset election. To date, no incentive distributions have been made.

(3) Held indirectly through CNP Midstream.

Distributions Received from Enable (CenterPoint Energy and CERC):

CenterPoint Energy

	Year Ended December 31,
	2019				2018				2017
	Per Unit		Cash Distribution		Per Unit		Cash Distribution		Per Unit		Cash Distribution
	(in millions, except per unit amounts)
Enable common units (1)	$	1.2970	$	303	$	1.2720	$	297	$	1.2720	$	297
Enable Series A Preferred Units	2.5000		36		2.5000		36		2.5000		36
Total CenterPoint Energy			$	339			$	333			$	333

CERC

	Year Ended December 31,
	2018				2017
	Per Unit		Cash Distribution		Per Unit		Cash Distribution
	(in millions, except per unit amounts)
Enable common units (1)	$	0.9540	$	223	$	1.2720	$	297
Total CERC			223				297

(1) Prior to the Internal Spin completed in September 2018, distributions from Enable were received by CERC. After such date, distributions from Enable were received directly by CenterPoint Energy (through CNP Midstream).

Transactions with Enable (CenterPoint Energy and CERC):

	Year Ended December 31,
	2019		2018		2017
CenterPoint Energy	(in millions)
Natural gas expenses, including transportation and storage costs (1)	$	120	$	122	$	115
Reimbursement of support services (2)	—		4		4
CERC
Natural gas expenses, including transportation and storage costs (1)	120		122		115
Reimbursement of support services (2)	—		4		4

(1) Included in Non-utility costs of revenues, including natural gas on CenterPoint Energy’s and CERC’s respective Statements of Consolidated Income.

(2) Represents amounts billed for certain support services provided to Enable. Actual support services costs are recorded net of reimbursement.

	December 31,
	2019		2018
CenterPoint Energy	(in millions)
Accounts payable for natural gas purchases from Enable	$	11	$	11
Accounts receivable for amounts billed for services provided to Enable	2		2
CERC
Accounts payable for natural gas purchases from Enable	11		11
Accounts receivable for amounts billed for services provided to Enable	2		2

CERC’s continuing involvement with Enable subsequent to the Internal Spin is limited to its natural gas purchases from Enable.

Summarized consolidated income (loss) information for Enable is as follows:

	Year Ended December 31,
	2019			2018			2017
	(in millions)
Operating revenues	$	2,960		$	3,431		$	2,803
Cost of sales, excluding depreciation and amortization	1,279			1,819			1,381
Depreciation and amortization	433			398			366
Operating income	569			648			528
Goodwill impairment	86			—			—
Net income attributable to Enable common units	360			485			400
Reconciliation of Equity in Earnings (Losses), net:
CenterPoint Energy’s interest	$	193		$	262		$	216
Basis difference amortization (1)	47			47			49
Loss on dilution, net of proportional basis difference recognition	(11		)	(2		)	—
CenterPoint Energy’s equity in earnings, net	$	229		$	307		$	265

(1) Equity in earnings of unconsolidated affiliate includes CenterPoint Energy’s share of Enable earnings adjusted for the amortization of the basis difference of CenterPoint Energy’s original investment in Enable and its underlying equity in net assets of Enable. The basis difference is being amortized through the year 2048.

Summarized consolidated balance sheet information for Enable is as follows:

	December 31,
	2019			2018
	(in millions)
Current assets	$	389		$	449
Non-current assets	11,877			11,995
Current liabilities	780			1,615
Non-current liabilities	4,077			3,211
Non-controlling interest	37			38
Preferred equity	362			362
Accumulated other comprehensive loss	(3		)	—
Enable partners’ equity	7,013			7,218
Reconciliation of Investment in Enable:
CenterPoint Energy’s ownership interest in Enable partners’ equity	$	3,767		$	3,896
CenterPoint Energy’s basis difference	(1,361		)	(1,414		)
CenterPoint Energy’s equity method investment in Enable	$	2,406		$	2,482

Discontinued Operations (CERC):

On September 4, 2018, CERC completed the Internal Spin. CERC executed the Internal Spin to, among other things, enhance the access of CERC and CenterPoint Energy to low cost debt and equity through increased transparency and understandability of the financial statements, improve CERC’s credit quality by eliminating the exposure to Enable’s midstream business and provide clarity of internal reporting and performance metrics to enhance management’s decision making for CERC and CNP Midstream.

The Internal Spin represents a significant strategic shift that has a material effect on CERC’s operations and financial results and, as a result, CERC’s distribution of its equity investment in Enable met the criteria for discontinued operations classification. CERC has no continuing involvement in the equity investment of Enable. Therefore, CERC’s equity in earnings and related income taxes have been classified as Income from discontinued operations, net of tax, in CERC’s Statements of Consolidated Income for the periods presented. CERC’s equity method investment and related deferred income tax liabilities have been classified as Investment in unconsolidated affiliate - discontinued operations and Deferred income taxes, net - discontinued operations, respectively, in CERC’s Consolidated Balance Sheets for the periods presented. The following table presents amounts included in Income from discontinued operations, net of tax in CERC’s Statements of Consolidated Income.

	Year Ended December 31,
	2018		2017
	(in millions)
Equity in earnings of unconsolidated affiliate, net	$	184	$	265
Income tax expense	46		104
Income from discontinued operations, net of tax	$	138	$	161

XML

Reportable Segments

12 Months Ended

Dec. 31, 2019

Segment Reporting [Abstract]

Reportable Segments [Text Block]

Reportable Segments

The Registrants’ determination of reportable segments considers the strategic operating units under which the Registrants manage sales, allocate resources and assess performance of various products and services to wholesale or retail customers in differing regulatory environments. The Registrants use operating income as the measure of profit or loss for the reportable segments other than Midstream Investments, where equity in earnings is used.

As of December 31, 2019, reportable segments by Registrant are as follows:

Registrants	Houston Electric T&D	Indiana Electric Integrated	Natural Gas Distribution	Energy Services	Infrastructure Services	Midstream Investments	Corporate and Other
CenterPoint Energy	X	X	X	X	X	X	X
Houston Electric	X
CERC			X	X			X

• CenterPoint Energy’s and Houston Electric’s Houston Electric T&D reportable segment consists of electric transmission and distribution services in the Texas Gulf Coast area.

• CenterPoint Energy’s Indiana Electric Integrated reportable segment consists of electric transmission and distribution services primarily to southwestern Indiana and includes power generation and wholesale power operations.

• CenterPoint Energy’s Natural Gas Distribution reportable segment consists of intrastate natural gas sales to, and natural gas transportation and distribution for residential, commercial, industrial and institutional customers in Arkansas, Indiana, Louisiana, Minnesota, Mississippi, Ohio, Oklahoma and Texas.

• CERC’s Natural Gas Distribution reportable segment consists of intrastate natural gas sales to, and natural gas transportation and distribution for residential, commercial, industrial and institutional customers in Arkansas, Louisiana, Minnesota, Mississippi, Oklahoma and Texas.

• CenterPoint Energy’s and CERC’s Energy Services reportable segment consists of non-rate regulated natural gas sales and services operations.

• CenterPoint Energy’s Infrastructure Services reportable segment consists of underground pipeline construction and repair services.

• CenterPoint Energy’s Midstream Investments reportable segment consists of the equity investment in Enable (excluding the Enable Series A Preferred Units).

• CenterPoint Energy’s Corporate and Other reportable segment consists of energy performance contracting and sustainable infrastructure services through ESG and other corporate operations which support all of the business operations of CenterPoint Energy.

• CERC’s Corporate and Other reportable segment consists primarily of corporate operations which support all of the business operations of CERC.

On February 3, 2020, CenterPoint Energy, through its subsidiary VUSI, entered into the Purchase Agreement to sell its Infrastructure Services reportable segment. The transaction is expected to close in the second quarter of 2020. For further information, see Notes 6 and 23 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. The transaction is expected to close in the second quarter of 2020. For further information, see Notes 6 and 23.

Expenditures for long-lived assets include property, plant and equipment. Intersegment sales are eliminated in consolidation, except as described in Note 2(b).

Financial data for reportable segments and products and services are as follows:

CenterPoint Energy

	Revenues from External Customers			Net Intersegment Revenues			Depreciation and Amortization		Operating Income (Loss)			Total Assets				Expenditures for Long-Lived Assets
	(in millions)
As of and for the year ended December 31, 2019:
Houston Electric T&D	$	2,996	(1)	$	—		$	648	$	624		$	11,264			$	1,033
Indiana Electric Integrated	523			—			91		90			3,168				183
Natural Gas Distribution	3,643			40			417		408			13,903				1,098
Energy Services	3,653			129			16		32			1,301				12
Infrastructure Services	1,186		(2)	4			50		95			1,077				67
Midstream Investments (3)	—			—			—		—			2,473				—
Corporate and Other	300			—			65		(23		)	4,784			(4)	194
Eliminations	—			(173		)	—		—			(2,531		)		—
Consolidated	$	12,301		$	—		$	1,287	$	1,226		$	35,439			$	2,587
Reconciling items																(81		)
Capital expenditures per Statements of Consolidated Cash Flows																$	2,506
As of and for the year ended December 31, 2018:
Houston Electric T&D	$	3,232	(1)	$	—		$	917	$	623		$	10,509			$	952
Natural Gas Distribution	2,931			36			277		266			6,956				638
Energy Services	4,411			110			16		(47		)	1,558				20
Midstream Investments (3)	—			—			—		—			2,482				—
Corporate and Other	15			—			33		(11		)	6,156			(4)	110
Eliminations	—			(146		)	—		—			(652		)		—
Consolidated	$	10,589		$	—		$	1,243	$	831		$	27,009			$	1,720
Reconciling items																(69		)
Capital expenditures per Statements of Consolidated Cash Flows																$	1,651
As of and for the year ended December 31, 2017:
Houston Electric T&D	$	2,997	(1)	$	—		$	724	$	636		$	10,292			$	924
Natural Gas Distribution	2,606			33			260		348			6,608				523
Energy Services	3,997			52			19		126			1,521				11
Midstream Investments (3)	—			—			—		—			2,472				—
Corporate and Other	14			—			33		26			2,497			(4)	36
Eliminations	—			(85		)	—		—			(654		)		—
Consolidated	$	9,614		$	—		$	1,036	$	1,136		$	22,736			$	1,494
Reconciling items																(68		)
Capital expenditures per Statements of Consolidated Cash Flows																$	1,426

(1) CenterPoint Energy’s Houston Electric T&D’s revenues from major customers are as follows:

	Year Ended December 31,
	2019		2018		2017
	(in millions)
Affiliates of NRG	$	727	$	705	$	713
Affiliates of Vistra Energy Corp.	263		251		229

(2) Includes revenues not eliminated in consolidation for pipeline construction and repair services of $162 million capitalized by CenterPoint Energy’s NGD for the 11 months ended December 31, 2019. See Note 2(b).

(3) CenterPoint Energy’s Midstream Investments’ equity earnings, net are as follows:

	Year Ended December 31,
	2019		2018		2016
	(in millions)
Enable	$	229	$	307	$	265

(4) Total assets included pension and other postemployment-related regulatory assets of $584 million, $665 million and $600 million as of December 31, 2019, 2018 and 2017, respectively. Additionally, total assets as of December 31, 2018 included $3.9 billion of temporary investments included in Cash and cash equivalents on CenterPoint Energy’s Consolidated Balance Sheets.

Houston Electric

Houston Electric consists of a single reportable segment; therefore, a tabular reportable segment presentation has not been

included.

(1) Houston Electric’s revenues from major external customers are as follows:

	Year Ended December 31,
	2019		2018		2017
	(in millions)
Affiliates of NRG	$	727	$	705	$	713
Affiliates of Vistra Energy Corp.	263		251		229

CERC

	Revenues from External Customers		Net Intersegment Revenues			Depreciation and Amortization		Operating Income (Loss)			Total Assets (1)			Expenditures for Long-Lived Assets
	(in millions)
As of and for the year ended December 31, 2019:
Natural Gas Distribution	$	2,911	$	40		$	289	$	316		$	7,497		$	773
Energy Services	3,654		128			16		32			1,301			12
Other Operations	5		—			—		2			149			—
Eliminations	—		(168		)	—		—			(508		)	—
Consolidated	$	6,570	$	—		$	305	$	350		$	8,439		$	785
Reconciling items														(9		)
Capital expenditures per Statements of Consolidated Cash Flows														$	776
As of and for the year ended December 31, 2018:
Natural Gas Distribution	$	2,931	$	36		$	277	$	266		$	6,956		$	638
Energy Services	4,411		110			16		(47		)	1,558			20
Other Operations	1		—			—		3			66			—
Eliminations	—		(146		)	—		—			(366		)	—
Consolidated	$	7,343	$	—		$	293	$	222		$	8,214		$	658
Reconciling items														(25		)
Capital expenditures per Statements of Consolidated Cash Flows														$	633

	Revenues from External Customers		Net Intersegment Revenues			Depreciation and Amortization		Operating Income (Loss)			Total Assets (1)				Expenditures for Long-Lived Assets
	(in millions)
As of and for the year ended December 31, 2017:
Natural Gas Distribution	$	2,606	$	33		$	260	$	348		$	6,608			$	523
Energy Services	3,997		52			19		126			1,521				11
Discontinued operations	—		—			—		—			2,472			(1)	—
Other Operations	—		—			—		(7		)	70				—
Eliminations	—		(85		)	—		—			(559		)		—
Consolidated	$	6,603	$	—		$	279	$	467		$	10,112			$	534
Reconciling items															(21		)
Capital expenditures per Statements of Consolidated Cash Flows															$	513

(1) On September 4, 2018, CERC completed the Internal Spin. For further information regarding the Internal Spin, see Note 11.

	Year Ended December 31,
	2019						2018						2017
Revenues by Products and Services:	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC
	(in millions)
Electric delivery	$	3,019	$	2,990	$	—	$	3,232	$	3,234	$	—	$	2,997	$	2,998	$	—
Retail electric sales	486		—		—		—		—		—		—		—		—
Wholesale electric sales	14		—		—		—		—		—		—		—		—
Retail gas sales	4,802		—		4,070		4,161		—		4,161		3,634		—		3,634
Wholesale gas sales	2,312		—		2,313		3,008		—		3,008		2,811		—		2,811
Gas transportation and processing	33		—		33		32		—		32		29		—		29
Infrastructure services	1,186		—		—		—		—		—		—		—		—
Energy products and services	449		—		154		156		—		142		143		—		129
Total	$	12,301	$	2,990	$	6,570	$	10,589	$	3,234	$	7,343	$	9,614	$	2,998	$	6,603

XML

Regulatory Matters Regulatory Assets and Regulatory Liabilities (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019		Dec. 31, 2018		Dec. 31, 2017
Schedule of Regulatory Assets and Liabilities [Line Items]
Securitized regulatory assets		$ 788		$ 1,059
Unrecognized equity return (2)	[1]	(168)		(213)
Unamortized loss on reacquired debt (3)	[2]	62		68
Non-current regulatory assets		2,117		1,967
Total regulatory assets		2,129		2,044
Non-current regulatory liabilities		3,474		2,525
Total regulatory liabilities		3,521		2,563
Total regulatory assets and liabilities, net		(1,392)		(519)
Amount of allowed equity return on the true-up balance that was recognized in the period		45		74		$ 42
Prepaid Expenses and Other Current Assets [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Current regulatory assets (1)	[3]	12		77
Other Current Liabilities [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Current regulatory liabilities (6)	[4]	47		38
Amounts related to TCJA [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-current regulatory liabilities	[5]	1,582		1,323
Removal Costs [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-current regulatory liabilities		1,429		886
Other Regulatory Assets (Liabilities) [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-current regulatory liabilities		463		316
Pension and Other Postretirement Plans Costs [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-current regulatory assets	[2]	637		725
Amounts related to TCJA [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-current regulatory assets	[2],[5]	30		33
Asset Retirement Obligation Costs [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-current regulatory assets	[2]	131		109
Other Regulatory Assets (Liabilities) [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-current regulatory assets		422		37
Remaining amounts of regulatory assets for which no return on investment during recovery period is provided		147	[6]	81	[2]
Hurricane Harvey [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-current regulatory assets	[2]	68		68
Houston Electric [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Securitized regulatory assets		788		1,059
Unrecognized equity return (2)	[1]	(168)		(213)
Unamortized loss on reacquired debt (3)	[2]	62		68
Non-current regulatory assets		915		1,124
Total regulatory assets		915		1,124
Non-current regulatory liabilities		1,288		1,298
Total regulatory liabilities		1,288		1,315
Total regulatory assets and liabilities, net		(373)		(191)
Amount of allowed equity return on the true-up balance that was recognized in the period		45		74		$ 42
Houston Electric [Member] | Prepaid Expenses and Other Current Assets [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Current regulatory assets (1)	[3]	0		0
Houston Electric [Member] | Other Current Liabilities [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Current regulatory liabilities (6)	[4]	0		17
Houston Electric [Member] | Amounts related to TCJA [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-current regulatory liabilities	[5]	821		847
Houston Electric [Member] | Removal Costs [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-current regulatory liabilities		244		269
Houston Electric [Member] | Other Regulatory Assets (Liabilities) [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-current regulatory liabilities		223		182
Houston Electric [Member] | Pension and Other Postretirement Plans Costs [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-current regulatory assets	[2]	34		33
Houston Electric [Member] | Amounts related to TCJA [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-current regulatory assets	[2],[5]	23		23
Houston Electric [Member] | Asset Retirement Obligation Costs [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-current regulatory assets	[2]	26		24
Houston Electric [Member] | Other Regulatory Assets (Liabilities) [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-current regulatory assets		29		11
Remaining amounts of regulatory assets for which no return on investment during recovery period is provided		57	[6]	55	[2]
Houston Electric [Member] | Hurricane Harvey [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-current regulatory assets	[2]	64		64
CERC Corp [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Securitized regulatory assets		0		0
Unrecognized equity return (2)	[1]	0		0
Unamortized loss on reacquired debt (3)	[2]	0		0
Non-current regulatory assets		191		181
Total regulatory assets		203		258
Non-current regulatory liabilities		1,219		1,227
Total regulatory liabilities		1,266		1,248
Total regulatory assets and liabilities, net		(1,063)		(990)
CERC Corp [Member] | Prepaid Expenses and Other Current Assets [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Current regulatory assets (1)	[3]	12		77
CERC Corp [Member] | Other Current Liabilities [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Current regulatory liabilities (6)	[4]	47		21
CERC Corp [Member] | Amounts related to TCJA [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-current regulatory liabilities	[5]	442		476
CERC Corp [Member] | Removal Costs [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-current regulatory liabilities		637		617
CERC Corp [Member] | Other Regulatory Assets (Liabilities) [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-current regulatory liabilities		140		134
CERC Corp [Member] | Pension and Other Postretirement Plans Costs [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-current regulatory assets	[2]	22		30
CERC Corp [Member] | Amounts related to TCJA [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-current regulatory assets	[2],[5]	7		10
CERC Corp [Member] | Asset Retirement Obligation Costs [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-current regulatory assets	[2]	94		85
CERC Corp [Member] | Other Regulatory Assets (Liabilities) [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-current regulatory assets		16		26
Remaining amounts of regulatory assets for which no return on investment during recovery period is provided		48	[6]	26	[2]
CERC Corp [Member] | Hurricane Harvey [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-current regulatory assets	[2]	$ 4		$ 4

[1] The unrecognized equity return will be recognized as it is recovered in rates through 2024. The timing of CenterPoint Energy’s and Houston Electric’s recognition of the equity return will vary each period based on amounts actually collected during the period. The actual amounts recognized are adjusted at least annually to correct any over-collections or under-collections during the preceding 12 months.   Year Ended December 31,   2019   2018   2017   CenterPoint Energy   Houston Electric   CenterPoint Energy   Houston Electric   CenterPoint Energy   Houston Electric     Allowed equity return recognized $ 45
  $ 45
  $ 74
  $ 74
  $ 42
  $ 42

[2] Substantially all of these regulatory assets are not earning a return.

[3] Current regulatory assets are included in Prepaid expenses and other current assets in the Registrants’ respective Consolidated Balance Sheets.

[4] Current regulatory liabilities are included in Other current liabilities in each of the Registrants’ respective Consolidated Balance Sheets.

[5] The EDIT and deferred revenues will be recovered or refunded to customers as required by tax and regulatory authorities. See Note 15 for additional information.

[6] Regulatory assets acquired in the Merger and not earning a return were recorded at fair value as of the Merger Date. Such fair value adjustments are recognized over time until the regulatory asset is recovered.

XML

Revenue Recognition Disaggregation of Revenue (Details) - USD ($) $ in Millions		3 Months Ended												12 Months Ended
		Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018		Sep. 30, 2018		Jun. 30, 2018		Mar. 31, 2018		Dec. 31, 2019		Dec. 31, 2018	Dec. 31, 2017
Disaggregation of Revenue [Line Items]
Revenue from contracts														$ 9,151		$ 6,745	$ 6,124
Derivatives income														3,311		4,024	3,568
Other (3)	[1]													12		(34)	7
Total revenues		$ 3,230	$ 2,742	$ 2,798	$ 3,531	$ 3,036		$ 2,212		$ 2,186		$ 3,155		12,301		10,589	9,614
Electric Transmission & Distribution [Member]
Disaggregation of Revenue [Line Items]
Total revenues	[2]													2,996		3,232	2,997
Indiana Electric Integrated [Member]
Disaggregation of Revenue [Line Items]
Total revenues	[2]													523
Natural Gas Distribution [Member]
Disaggregation of Revenue [Line Items]
Total revenues														3,643		2,931	2,606
Energy Services [Member]
Disaggregation of Revenue [Line Items]
Total revenues														3,653		4,411	3,997
Infrastructure Services [Member]
Disaggregation of Revenue [Line Items]
Total revenues	[3]													1,186
Corporate and Other [Member]
Disaggregation of Revenue [Line Items]
Total revenues														300		15	14
Intersegment Eliminations [Member]
Disaggregation of Revenue [Line Items]
Total revenues														(173)		(146)	(85)
Intersegment Eliminations [Member] | Electric Transmission & Distribution [Member]
Disaggregation of Revenue [Line Items]
Total revenues														0		0	0
Intersegment Eliminations [Member] | Natural Gas Distribution [Member]
Disaggregation of Revenue [Line Items]
Total revenues														(40)		(36)	(33)
Intersegment Eliminations [Member] | Energy Services [Member]
Disaggregation of Revenue [Line Items]
Total revenues														(129)		(110)	(52)
Intersegment Eliminations [Member] | Infrastructure Services [Member]
Disaggregation of Revenue [Line Items]
Total revenues														(4)
Intersegment Eliminations [Member] | Corporate and Other [Member]
Disaggregation of Revenue [Line Items]
Total revenues														0		0	0
Reportable Subsegments [Member] | Electric Transmission & Distribution [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts	[4]													2,984		3,235	3,001
Derivatives income	[4]													6		(2)	(1)
Other (3)	[1],[4]													6		(1)	(3)
Total revenues	[4]													2,996		3,232	2,997
Reportable Subsegments [Member] | Indiana Electric Integrated [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts	[4]													523	[5]	0	0
Derivatives income	[4]													0	[5]	0	0
Other (3)	[1],[4]													0	[5]	0	0
Total revenues	[4]													523	[5]	0	0
Reportable Subsegments [Member] | Natural Gas Distribution [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts	[4]													3,680	[5]	3,011	2,638
Derivatives income	[4]													2	[5]	(2)	0
Other (3)	[1],[4]													1	[5]	(42)	1
Total revenues	[4]													3,643	[5]	2,931	2,606
Reportable Subsegments [Member] | Energy Services [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts	[6]													479		493	480
Derivatives income	[6]													3,303		4,028	3,569
Other (3)	[1],[6]															0	0
Total revenues	[6]													3,653		4,411	3,997
Reportable Subsegments [Member] | Infrastructure Services [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts	[6]													1,190	[5]	0	0
Derivatives income	[6]															0	0
Other (3)	[1],[6]															0	0
Total revenues	[6]													1,186	[5]	0	0
Reportable Subsegments [Member] | Corporate and Other [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts	[6]													295	[5]	6	5
Derivatives income	[6]															0	0
Other (3)	[1],[6]													5	[5]	9	9
Total revenues	[6]													300	[5]	15	14
Reportable Subsegments [Member] | Intersegment Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts	[4]													(40)	[5]	(36)	(33)
Derivatives income	[6]													(129)		(110)	(52)
Total revenues														(173)		(146)	(85)
Reportable Subsegments [Member] | Intersegment Eliminations [Member] | Infrastructure Services [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts	[6]													(4)	[5]	0	0
Houston Electric [Member]
Disaggregation of Revenue [Line Items]
Total revenues		680	859	765	686	728		897		854		755		2,990		3,234	2,998
Houston Electric [Member] | Reportable Subsegments [Member] | Electric Transmission & Distribution [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts														2,984		3,235	3,001
Other (3)	[7]													6		(1)	(3)
Total revenues														2,990		3,234	2,998
CERC Corp [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts														3,430		3,505	3,118
Derivatives income														3,304		4,026	3,569
Other (3)	[8]													4		(42)	1
Total revenues		$ 1,734	$ 1,126	$ 1,342	$ 2,368	$ 2,303	[9]	$ 1,312	[9]	$ 1,328	[9]	$ 2,400	[9]	6,570		7,343	6,603
CERC Corp [Member] | Natural Gas Distribution [Member]
Disaggregation of Revenue [Line Items]
Total revenues														2,911		2,931	2,606
CERC Corp [Member] | Energy Services [Member]
Disaggregation of Revenue [Line Items]
Total revenues														3,654		4,411	3,997
CERC Corp [Member] | Corporate and Other [Member]
Disaggregation of Revenue [Line Items]
Total revenues														5		1	0
CERC Corp [Member] | Intersegment Eliminations [Member]
Disaggregation of Revenue [Line Items]
Total revenues														(168)		(146)	(85)
CERC Corp [Member] | Intersegment Eliminations [Member] | Natural Gas Distribution [Member]
Disaggregation of Revenue [Line Items]
Total revenues														(40)		(36)	(33)
CERC Corp [Member] | Intersegment Eliminations [Member] | Energy Services [Member]
Disaggregation of Revenue [Line Items]
Total revenues														(128)		(110)	(52)
CERC Corp [Member] | Intersegment Eliminations [Member] | Corporate and Other [Member]
Disaggregation of Revenue [Line Items]
Total revenues														0		0	0
CERC Corp [Member] | Reportable Subsegments [Member] | Natural Gas Distribution [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts	[10]													2,945		3,011	2,638
Derivatives income	[10]													2		(2)	0
Other (3)	[8],[10]													4		(42)	1
Total revenues	[10]													2,911		2,931	2,606
CERC Corp [Member] | Reportable Subsegments [Member] | Energy Services [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts	[11]													480		493	480
Derivatives income	[11]													3,302		4,028	3,569
Other (3)	[8],[11]													0		0	0
Total revenues	[11]													3,654		4,411	3,997
CERC Corp [Member] | Reportable Subsegments [Member] | Corporate and Other [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts	[11]													5		1	0
Derivatives income	[11]													0		0	0
Other (3)	[8],[11]													0		0	0
Total revenues	[11]													5		1	0
CERC Corp [Member] | Reportable Subsegments [Member] | Intersegment Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts	[10]													(40)		(36)	(33)
Derivatives income	[11]													(128)		(110)	(52)
Total revenues														$ (168)		$ (146)	$ (85)

[1] Primarily consists of income from ARPs and leases. ARPs are contracts between the utility and its regulators, not between the utility and a customer. The Registrants recognize ARP revenue as other revenues when the regulator-specified conditions for recognition have been met. Upon recovery of ARP revenue through incorporation in rates charged for utility service to customers, ARP revenue is reversed and recorded as revenue from contracts with customers. The recognition of ARP revenues and the reversal of ARP revenues upon recovery through rates charged for utility service may not occur in the same period.

[2] CenterPoint Energy’s Houston Electric T&D’s revenues from major customers are as follows:     Year Ended December 31,     2019   2018   2017     (in millions) Affiliates of NRG   $ 727
  $ 705
  $ 713
Affiliates of Vistra Energy Corp.   263
  251
  229

[3] Includes revenues not eliminated in consolidation for pipeline construction and repair services of $162 million capitalized by CenterPoint Energy’s NGD for the 11 months ended December 31, 2019. See Note 2(b).

[4] Reflected in Utility revenues in the Statements of Consolidated Income.

[5] Reflects revenues from Vectren subsidiaries for the period from February 1, 2019 to December 31, 2019.

[6] Reflected in Non-utility revenues in the Statements of Consolidated Income.

[7] Primarily consists of income from ARPs and leases. ARPs are contracts between the utility and its regulators, not between the utility and a customer. The Registrants recognize ARP revenue as other revenues when the regulator-specified conditions for recognition have been met. Upon recovery of ARP revenue through incorporation in rates charged for utility service to customers, ARP revenue is reversed and recorded as revenue from contracts with customers. The recognition of ARP revenues and the reversal of ARP revenues upon recovery through rates charged for utility service may not occur in the same period.

[8] Primarily consists of income from ARPs and leases. ARPs are contracts between the utility and its regulators, not between the utility and a customer. The Registrants recognize ARP revenue as other revenues when the regulator-specified conditions for recognition have been met. Upon recovery of ARP revenue through incorporation in rates charged for utility service to customers, ARP revenue is reversed and recorded as revenue from contracts with customers. The recognition of ARP revenues and the reversal of ARP revenues upon recovery through rates charged for utility service may not occur in the same period.

[9] Amounts have been recast to reflect discontinued operations in all periods presented.

[10] Reflected in Utility revenues in the Statements of Consolidated Income.

[11] Reflected in Non-utility revenues in the Statements of Consolidated Income.

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CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($)		Dec. 31, 2019	Dec. 31, 2018
Current Assets:
Cash and cash equivalents	[1]	$ 241,000,000	$ 4,231,000,000
Bad debt reserve		21,000,000	18,000,000
Accounts receivable		1,249,000,000	1,190,000,000
Prepaid expense and other current assets		161,000,000	192,000,000
Other Assets:
Regulatory assets		$ 2,117,000,000	$ 1,967,000,000
Shareholders’ Equity:
Cumulative preferred stock par value (in dollars per share)		$ 0.01	$ 0.01
Cumulative preferred stock authorized (in shares)		20,000,000	20,000,000
Common stock par value (in dollars per share)		$ 0.01	$ 0.01
Common stock authorized (in shares)		1,000,000,000	1,000,000,000
Common stock outstanding (in shares)		502,242,061	501,197,784
Variable Interest Entity, Primary Beneficiary [Member]
Current Assets:
Cash and cash equivalents		$ 216,000,000	$ 335,000,000
Accounts receivable		26,000,000	56,000,000
Prepaid expense and other current assets		19,000,000	34,000,000
Other Assets:
Regulatory assets		788,000,000	1,059,000,000
Houston Electric [Member]
Current Assets:
Cash and cash equivalents	[2]	216,000,000	335,000,000
Prepaid expense and other current assets		49,000,000	61,000,000
Other Assets:
Regulatory assets		915,000,000	1,124,000,000
Houston Electric [Member] | Variable Interest Entity, Primary Beneficiary [Member]
Current Assets:
Cash and cash equivalents		216,000,000	335,000,000
Bad debt reserve		1,000,000	1,000,000
Accounts receivable		26,000,000	56,000,000
Prepaid expense and other current assets		19,000,000	34,000,000
Other Assets:
Regulatory assets		788,000,000	1,059,000,000
CERC Corp [Member]
Current Assets:
Cash and cash equivalents		2,000,000	14,000,000
Bad debt reserve		15,000,000	17,000,000
Accounts receivable		693,000,000	894,000,000
Prepaid expense and other current assets		44,000,000	115,000,000
Other Assets:
Regulatory assets		$ 191,000,000	$ 181,000,000
Cumulative Preferred Stock [Member]
Shareholders’ Equity:
Cumulative preferred stock par value (in dollars per share)		$ 0.01	$ 0.01
Cumulative preferred stock authorized (in shares)		20,000,000	20,000,000
Series A Preferred Stock [Member]
Shareholders’ Equity:
Cumulative preferred stock par value (in dollars per share)		$ 0.01	$ 0.01
Preferred Stock, Liquidation Preference, Value		$ 800,000,000	$ 800,000,000
Cumulative preferred stock outstanding (in shares)		800,000	800,000
Series B Preferred Stock [Member]
Shareholders’ Equity:
Cumulative preferred stock par value (in dollars per share)		$ 0.01	$ 0.01
Preferred Stock, Liquidation Preference, Value		$ 977,500,000	$ 977,500,000
Cumulative preferred stock outstanding (in shares)		977,500	977,500

[1] CenterPoint Energy’s Cash and cash equivalents as of December 31, 2018 included $3.9 billion of temporary investments resulting from the Merger financings. CenterPoint Energy recorded interest income of $22 million, $28 million and $2 million for the years ended December 31, 2019, 2018 and 2017, respectively, in Other, net on CenterPoint Energy’s Statements of Consolidated Income. See Notes 13 and 14 for further details related to the Merger financings.

[2] Houston Electric’s Cash and cash equivalents as of December 31, 2019 and 2018 included $216 million and $335 million, respectively, of cash related to the Bond Companies. Houston Electric recorded interest income of $9 million, $4 million and $2 million for the years ended December 31, 2019, 2018 and 2017, respectively, in Other, net on Houston Electric’s Statement of Consolidated Income.

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STATEMENTS OF CONSOLIDATED INCOME (Parentheticals) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
CERC Corp [Member]
Income tax expense (benefit) associated with discontinued operations	$ 0	$ 46	$ 104

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Regulatory Matters (Tables)

12 Months Ended

Dec. 31, 2019

Regulated Operations [Abstract]

Schedule of Regulatory Assets and Liabilities [Table Text Block]

The following is a list of regulatory assets and liabilities reflected on the Registrants’ respective Consolidated Balance Sheets as of December 31, 2019 and 2018. The “amortization through” columns indicate the latest year when a regulatory asset or regulatory liability category will be fully amortized:

	December 31, 2019
	CenterPoint Energy				Houston Electric				CERC
	Amortization Through	(in millions)			Amortization Through	(in millions)			Amortization Through	(in millions)
Regulatory Assets:
Current regulatory assets (1)	2020	$	12		n/a	$	—		2020	$	12
Non-current regulatory assets:
Securitized regulatory assets	2024	788			2024	788			n/a	—
Unrecognized equity return (2)	2024	(168		)	2024	(168		)	n/a	—
Unamortized loss on reacquired debt (3)	2046	62			2046	62			n/a	—
Pension and postretirement-related regulatory asset (3)	Various (a)	637			TBD (b)	34			Various (a)	22
Hurricane Harvey restoration costs (3)	Various	68			TBD (b)	64			TBD (c)	4
Regulatory assets related to TCJA (3) (4)	Various	30			TBD (b)	23			2023	7
Asset retirement obligation (3)	Perpetual	131			Perpetual	26			Perpetual	94
Other regulatory assets-not earning a return (5)	Various (d)	147			Various	57			Various	48
Other regulatory assets	Various	422			Various	29			Various	16
Total non-current regulatory assets		2,117				915				191
Total regulatory assets		2,129				915				203
Regulatory Liabilities:
Current regulatory liabilities (6)	2020	47			n/a	—			2020	47
Non-current regulatory liabilities:
Regulatory liabilities related to TCJA (4)	Various	1,582			TBD (b)	821			Various	442
Estimated removal costs	Various	1,429			Various	244			Various	637
Other regulatory liabilities	Various	463			Various	223			Various	140
Total non-current regulatory liabilities		3,474				1,288				1,219
Total regulatory liabilities		3,521				1,288				1,266
Total regulatory assets and liabilities, net		$	(1,392	)		$	(373	)		$	(1,063	)

(a) Pension and postretirement-related regulatory assets balances are measured annually, and the ending amortization period may change based on the actuarial valuation.

(b) The recovery and amortization of these amounts are to be determined upon receipt of the final order.

(c) The recovery and amortization of a portion of these amounts are expected to be determined in the next rate case.

(d) Other regulatory assets not-earning a return includes items with different amortization periods; therefore, the amortization is accounted for through various periods.

	December 31, 2018
	CenterPoint Energy			Houston Electric			CERC
	(in millions)
Regulatory Assets:
Current regulatory assets (1)	$	77		$	—		$	77
Non-current regulatory assets:
Securitized regulatory assets	1,059			1,059			—
Unrecognized equity return (2)	(213		)	(213		)	—
Unamortized loss on reacquired debt (3)	68			68			—
Pension and postretirement-related regulatory asset (3)	725			33			30
Hurricane Harvey restoration costs (3)	68			64			4
Regulatory assets related to TCJA (3) (4)	33			23			10
Asset retirement obligation (3)	109			24			85
Other regulatory assets-not earning a return (3)	81			55			26
Other regulatory assets	37			11			26
Total non-current regulatory assets	1,967			1,124			181
Total regulatory assets	2,044			1,124			258
Regulatory Liabilities:
Current regulatory liabilities (6)	38			17			21
Non-current regulatory liabilities:
Regulatory liabilities related to TCJA (4)	1,323			847			476
Estimated removal costs	886			269			617
Other regulatory liabilities	316			182			134
Total non-current regulatory liabilities	2,525			1,298			1,227
Total regulatory liabilities	2,563			1,315			1,248
Total regulatory assets and liabilities, net	$	(519	)	$	(191	)	$	(990	)

(1) Current regulatory assets are included in Prepaid expenses and other current assets in the Registrants’ respective Consolidated Balance Sheets.

(2) The unrecognized equity return will be recognized as it is recovered in rates through 2024. The timing of CenterPoint Energy’s and Houston Electric’s recognition of the equity return will vary each period based on amounts actually collected during the period. The actual amounts recognized are adjusted at least annually to correct any over-collections or under-collections during the preceding 12 months.

	Year Ended December 31,
	2019				2018				2017
	CenterPoint Energy		Houston Electric		CenterPoint Energy		Houston Electric		CenterPoint Energy		Houston Electric
Allowed equity return recognized	$	45	$	45	$	74	$	74	$	42	$	42

(3) Substantially all of these regulatory assets are not earning a return.

(4) The EDIT and deferred revenues will be recovered or refunded to customers as required by tax and regulatory authorities. See Note 15 for additional information.

(5) Regulatory assets acquired in the Merger and not earning a return were recorded at fair value as of the Merger Date. Such fair value adjustments are recognized over time until the regulatory asset is recovered.

(6)

Current regulatory liabilities are included in Other current liabilities in each of the Registrants’ respective Consolidated Balance Sheets.

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Unconsolidated Affiliate (CenterPoint Energy and CERC) (Tables)

12 Months Ended

Dec. 31, 2019

Equity Method Investments and Joint Ventures [Abstract]

Equity Method Investments [Table Text Block]

Limited Partner Interest and Units Held in Enable (CenterPoint Energy):

	As of December 31,
	2019				2018
	Limited Partner Interest (1)		Common Units	Enable Series A Preferred Units (2)	Limited Partner Interest (1)		Common Units	Enable Series A Preferred Units (2)
CenterPoint Energy (3)	53.7	%	233,856,623	14,520,000	54.0	%	233,856,623	14,520,000
OGE	25.5	%	110,982,805	—	25.6	%	110,982,805	—
Public unitholders	20.8	%	90,361,937	—	20.4	%	88,392,983	—
Total Units Outstanding	100.0	%	435,201,365	14,520,000	100.0	%	433,232,411	14,520,000

(1) Excludes the Enable Series A Preferred Units owned by CenterPoint Energy.

(2) The carrying amount of the Enable Series A Preferred Units, reflected as Preferred units - unconsolidated affiliate on CenterPoint Energy’s Consolidated Balance Sheets, was $363 million as of both December 31, 2019 and 2018. No

impairment charges or adjustment to carrying value were made as no observable price changes were identified in the current or prior reporting periods.

(3)

Prior to the Internal Spin completed in September 2018, CenterPoint Energy’s investment in Enable’s common units, excluding the Enable Series A Preferred Units held directly by CenterPoint Energy, was held indirectly through CERC.

Interests Held in Enable GP (CenterPoint Energy):

CenterPoint Energy and OGE held the following interests in Enable GP as of both December 31, 2019 and 2018:

	Management  Rights (1)		Incentive Distribution Rights (2)
CenterPoint Energy (3)	50	%	40	%
OGE	50	%	60	%

(1) As of December 31, 2019, Enable is controlled jointly by CenterPoint Energy and OGE. Sale of CenterPoint Energy’s or OGE’s ownership interests in Enable GP to a third party is subject to mutual rights of first offer and first refusal, and CenterPoint Energy is not permitted to dispose of less than all of its interest in Enable GP.

(2) Enable is expected to pay a minimum quarterly distribution of $0.2875 per common unit on its outstanding common units to the extent it has sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to Enable GP and its affiliates, within 60 days after the end of each quarter. If cash distributions to Enable’s unitholders exceed $0.330625 per common unit in any quarter, Enable GP will receive increasing percentages or incentive distributions rights, up to 50%, of the cash Enable distributes in excess of that amount. In certain circumstances Enable GP will have the right to reset the minimum quarterly distribution and the target distribution levels at which the incentive distributions receive increasing percentages to higher levels based on Enable’s cash distributions at the time of the exercise of this reset election. To date, no incentive distributions have been made.

(3) Held indirectly through CNP Midstream.

Distributions Received from Enable (CenterPoint Energy and CERC):

CenterPoint Energy

	Year Ended December 31,
	2019				2018				2017
	Per Unit		Cash Distribution		Per Unit		Cash Distribution		Per Unit		Cash Distribution
	(in millions, except per unit amounts)
Enable common units (1)	$	1.2970	$	303	$	1.2720	$	297	$	1.2720	$	297
Enable Series A Preferred Units	2.5000		36		2.5000		36		2.5000		36
Total CenterPoint Energy			$	339			$	333			$	333

CERC

	Year Ended December 31,
	2018				2017
	Per Unit		Cash Distribution		Per Unit		Cash Distribution
	(in millions, except per unit amounts)
Enable common units (1)	$	0.9540	$	223	$	1.2720	$	297
Total CERC			223				297

(1) Prior to the Internal Spin completed in September 2018, distributions from Enable were received by CERC. After such date, distributions from Enable were received directly by CenterPoint Energy (through CNP Midstream).

Transactions with Enable (CenterPoint Energy and CERC):

	Year Ended December 31,
	2019		2018		2017
CenterPoint Energy	(in millions)
Natural gas expenses, including transportation and storage costs (1)	$	120	$	122	$	115
Reimbursement of support services (2)	—		4		4
CERC
Natural gas expenses, including transportation and storage costs (1)	120		122		115
Reimbursement of support services (2)	—		4		4

(1) Included in Non-utility costs of revenues, including natural gas on CenterPoint Energy’s and CERC’s respective Statements of Consolidated Income.

(2) Represents amounts billed for certain support services provided to Enable. Actual support services costs are recorded net of reimbursement.

	December 31,
	2019		2018
CenterPoint Energy	(in millions)
Accounts payable for natural gas purchases from Enable	$	11	$	11
Accounts receivable for amounts billed for services provided to Enable	2		2
CERC
Accounts payable for natural gas purchases from Enable	11		11
Accounts receivable for amounts billed for services provided to Enable	2		2

CERC’s continuing involvement with Enable subsequent to the Internal Spin is limited to its natural gas purchases from Enable.

Summarized consolidated income (loss) information for Enable is as follows:

	Year Ended December 31,
	2019			2018			2017
	(in millions)
Operating revenues	$	2,960		$	3,431		$	2,803
Cost of sales, excluding depreciation and amortization	1,279			1,819			1,381
Depreciation and amortization	433			398			366
Operating income	569			648			528
Goodwill impairment	86			—			—
Net income attributable to Enable common units	360			485			400
Reconciliation of Equity in Earnings (Losses), net:
CenterPoint Energy’s interest	$	193		$	262		$	216
Basis difference amortization (1)	47			47			49
Loss on dilution, net of proportional basis difference recognition	(11		)	(2		)	—
CenterPoint Energy’s equity in earnings, net	$	229		$	307		$	265

(1) Equity in earnings of unconsolidated affiliate includes CenterPoint Energy’s share of Enable earnings adjusted for the amortization of the basis difference of CenterPoint Energy’s original investment in Enable and its underlying equity in net assets of Enable. The basis difference is being amortized through the year 2048.

Summarized consolidated balance sheet information for Enable is as follows:

	December 31,
	2019			2018
	(in millions)
Current assets	$	389		$	449
Non-current assets	11,877			11,995
Current liabilities	780			1,615
Non-current liabilities	4,077			3,211
Non-controlling interest	37			38
Preferred equity	362			362
Accumulated other comprehensive loss	(3		)	—
Enable partners’ equity	7,013			7,218
Reconciliation of Investment in Enable:
CenterPoint Energy’s ownership interest in Enable partners’ equity	$	3,767		$	3,896
CenterPoint Energy’s basis difference	(1,361		)	(1,414		)
CenterPoint Energy’s equity method investment in Enable	$	2,406		$	2,482

Investment in Unconsolidated Affiliates (CenterPoint Energy):

	December 31, 2019		December 31, 2018
	(in millions)
Enable	$	2,406	$	2,482
Other (1)	2		—
Total	$	2,408	$	2,482

(1) Represents the fair value of non-utility equity investments acquired in the Merger.

CenterPoint Energy evaluates its equity method investments for impairment when factors indicate that a decrease in value of its investment has occurred and the carrying amount of its investment may not be recoverable. An impairment loss is recognized in earnings when an impairment is deemed to be other than temporary. As of December 31, 2019, CenterPoint Energy’s investment in Enable is $10.29 per unit and Enable’s common unit price closed at $10.03 per unit (approximately $61 million below carrying value). Based on an analysis of its investment in Enable as of December 31, 2019, CenterPoint Energy believes that the decline in the value of its investment is temporary, and that the carrying value of its investment of $2.4 billion will be recovered.

Equity in Earnings of Unconsolidated Affiliates, net (CenterPoint Energy):

	Year Ended December 31,
	2019		2018		2017
	(in millions)
Enable (1)	$	229	$	307	$	265
Other	1		—		—
Total	$	230	$	307	$	265

(1) Equity earnings for the year ended December 31, 2019 includes CenterPoint Energy’s share of Enable’s $86 million goodwill impairment recorded in the fourth quarter of 2019.

Disposal Groups, Including Discontinued Operations [Table Text Block]

The Internal Spin represents a significant strategic shift that has a material effect on CERC’s operations and financial results and, as a result, CERC’s distribution of its equity investment in Enable met the criteria for discontinued operations classification. CERC has no continuing involvement in the equity investment of Enable. Therefore, CERC’s equity in earnings and related income taxes have been classified as Income from discontinued operations, net of tax, in CERC’s Statements of Consolidated Income for the periods presented. CERC’s equity method investment and related deferred income tax liabilities have been classified as Investment in unconsolidated affiliate - discontinued operations and Deferred income taxes, net - discontinued operations, respectively, in CERC’s Consolidated Balance Sheets for the periods presented. The following table presents amounts included in Income from discontinued operations, net of tax in CERC’s Statements of Consolidated Income.

	Year Ended December 31,
	2018		2017
	(in millions)
Equity in earnings of unconsolidated affiliate, net	$	184	$	265
Income tax expense	46		104
Income from discontinued operations, net of tax	$	138	$	161

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2019

Income Tax Disclosure [Abstract]

Summary of Income Tax Contingencies [Table Text Block]

A reconciliation of CenterPoint Energy’s beginning and ending balance of unrecognized tax benefits, excluding interest and penalties, for 2019 is as follows:

	Year Ended December 31, 2019
	(in millions)
Balance, beginning of year	$	—
Unrecognized tax benefits assumed through the Merger	9
Decreases related to tax positions of prior years	(1		)
Balance, end of year	$	8

CenterPoint Energy had no unrecognized tax benefits for 2018 and 2017.

Income Tax Expense [Table Text Block]

The components of the Registrant’ income tax expense (benefit) were as follows:

	Year Ended December 31,
	2019			2018			2017
	(in millions)
CenterPoint Energy
Current income tax expense:
Federal	$	48		$	89		$	32
State	21			9			9
Total current expense	69			98			41
Deferred income tax expense (benefit):
Federal	74			(25		)	(806		)
State	(5		)	73			36
Total deferred expense (benefit)	69			48			(770		)
Total income tax expense (benefit)	$	138		$	146		$	(729	)
Houston Electric
Current income tax expense:
Federal	$	84		$	109		$	70
State	20			18			19
Total current expense	104			127			89
Deferred income tax benefit:
Federal	(24		)	(38		)	(98		)
Total deferred benefit	(24		)	(38		)	(98		)
Total income tax expense (benefit)	$	80		$	89		$	(9	)
CERC - Continuing Operations
Current income tax expense (benefit):
Federal	$	—		$	(9	)	$	(31	)
State	7			—			(10		)
Total current expense (benefit)	7			(9		)	(41		)
Deferred income tax expense (benefit):
Federal	39			10			(249		)
State	(32		)	21			25
Total deferred expense (benefit)	7			31			(224		)
Total income tax expense (benefit)	$	14		$	22		$	(265	)
CERC - Discontinued Operations
Current income tax expense (benefit):
Federal	$	—		$	9		$	31
State	—			4			11
Total current expense (benefit)	—			13			42
Deferred income tax expense:
Federal	—			29			56
State	—			4			6
Total deferred expense	—			33			62
Total income tax expense	$	—		$	46		$	104

Reconciliation of Expected Federal Income Tax Expense to Actual [Table Text Block]

A reconciliation of income tax expense (benefit) using the federal statutory income tax rate to the actual income tax expense and resulting effective income tax rate is as follows:

	Year Ended December 31,
	2019			2018			2017
	(in millions)
CenterPoint Energy (1) (2) (3)
Income before income taxes	$	929		$	514		$	1,063
Federal statutory income tax rate	21		%	21		%	35		%
Expected federal income tax expense	195			108			372
Increase (decrease) in tax expense resulting from:
State income tax expense, net of federal income tax	36			22			26
State valuation allowance, net of federal income tax	(4		)	11			3
State law change, net of federal income tax	(21		)	32			—
Federal income tax rate reduction	—			—			(1,113		)
Excess deferred income tax amortization	(55		)	(24		)	—
Other, net	(13		)	(3		)	(17		)
Total	(57		)	38			(1,101		)
Total income tax expense (benefit)	$	138		$	146		$	(729	)
Effective tax rate	15		%	28		%	(69		)%
Houston Electric (4) (5) (6)
Income before income taxes	$	436		$	425		$	424
Federal statutory income tax rate	21		%	21		%	35		%
Expected federal income tax expense	92			89			148
Increase (decrease) in tax expense resulting from:
State income tax expense, net of federal income tax	16			14			12
Federal income tax rate reduction	—			—			(158		)
Excess deferred income tax amortization	(21		)	(9		)	—
Other, net	(7		)	(5		)	(11		)
Total	(12		)	—			(157		)
Total income tax expense (benefit)	$	80		$	89		$	(9	)
Effective tax rate	18		%	21		%	(2		)%
CERC - Continuing Operations (7) (8) (9)
Income before income taxes	$	226		$	92		$	319
Federal statutory income tax rate	21		%	21		%	35		%
Expected federal income tax expense	47			19			112
Increase (decrease) in tax expense resulting from:
State income tax expense, net of federal income tax	(12		)	5			6
State law change, net of federal income tax	(4		)	—			—
State valuation allowance, net of federal income tax	(4		)	11			3
Federal income tax rate reduction	—			—			(396		)
Goodwill impairment	8			—			—
Excess deferred income tax amortization	(18		)	(15		)	—
Tax basis balance sheet adjustment	—			—			11
Other, net	(3		)	2			(1		)
Total	(33		)	3			(377		)
Total income tax expense (benefit)	$	14		$	22		$	(265	)
Effective tax rate	6		%	24		%	(83		)%

	Year Ended December 31,
	2019			2018			2017
	(in millions)
CERC - Discontinued Operations (9)
Income before income taxes	$	—		$	184		$	265
Federal statutory income tax rate	—		%	21		%	35		%
Expected federal income tax expense	—			39			93
Increase in tax expense resulting from:
State income tax expense, net of federal income tax	—			7			11
Total	—			7			11
Total income tax expense	$	—		$	46		$	104
Effective tax rate	—		%	25		%	39		%

(1) Recognized a $55 million benefit for the amortization of the net regulatory EDIT liability as decreed by regulators in certain jurisdictions, a $21 million net benefit for the impact of state law changes that resulted in the remeasurement of state deferred taxes in those jurisdictions, and $4 million net benefit for the reduction in valuation allowances on certain state net operating losses that are now expected to be realized.

(2) Recognized a $32 million deferred tax expense due to state law changes that resulted in remeasurement of state deferred taxes in those jurisdictions. Also recorded an additional $11 million valuation allowance on certain state net operating loss deferred tax assets that are no longer expected to be utilized prior to expiration after the Internal Spin. These items are partially offset by $24 million of amortization of the net regulatory EDIT liability as decreed by regulators in certain jurisdictions beginning in 2018.

(3) Recognized a $1.1 billion deferred tax benefit from the remeasurement of CenterPoint Energy’s ADFIT liability as a result of the enactment of the TCJA on December 22, 2017, which reduced the U.S. corporate income tax rate from 35% to 21%.

(4) Recognized $21 million of amortization of the net regulatory EDIT liability as decreed by regulators.

(5) Recognized $9 million of amortization of the net regulatory EDIT liability as decreed by regulators in certain jurisdictions beginning in 2018.

(6) Recognized a $158 million deferred tax benefit from the remeasurement of Houston Electric’s ADFIT liability as a result of the enactment of the TCJA on December 22, 2017, which reduced the U.S. corporate income tax rate from 35% to 21%.

(7) Recognized $18 million benefit for the amortization of the net regulatory EDIT liability as decreed by regulators in certain jurisdictions, $4 million net benefit for the impact of state law changes that resulted in the remeasurement of state deferred taxes in those jurisdictions and $4 million net benefit for the reduction in valuation allowances on certain state net operating losses that are now expected to be realized.

(8) Recorded an additional $11 million valuation allowance on certain state net operating loss deferred tax assets that are no longer expected to be utilized prior to expiration after the Internal Spin. This item is partially offset by $15 million of amortization of the net regulatory EDIT liability in certain jurisdictions as decreed by regulators beginning in 2018.

(9) Recognized a $396 million deferred tax benefit from the remeasurement of CERC’s ADFIT liability as a result of the enactment of the TCJA on December 22, 2017, which reduced the U.S. corporate income tax rate from 35% to 21%. ASC 740 requires tax impacts of changes in tax laws or rates be reported in continuing operations. Therefore, CERC’s federal income tax benefit generated by the remeasurement of the ADFIT liability for Enable during 2017 and state law changes during 2016 associated with its investment in Enable are reported in continuing operations on CERC’s Statements of Consolidated Income. The ADFIT liability associated with CERC’s investment in Enable is reported as discontinued operations on CERC’s Consolidated Balance Sheets. 

Tax Assets and Liabilities [Table Text Block]

The tax effects of temporary differences that give rise to significant portions of deferred tax assets and liabilities were as follows:

	December 31,
	2019			2018
	(in millions)
CenterPoint Energy
Deferred tax assets:
Benefits and compensation	$	152		$	160
Regulatory liabilities	447			356
Loss and credit carryforwards	111			84
Asset retirement obligations	89			62
Indexed debt securities derivative	34			—
Other	40			29
Valuation allowance	(25		)	(18		)
Total deferred tax assets	848			673
Deferred tax liabilities:
Property, plant and equipment	2,656			1,894
Investment in unconsolidated affiliates	1,010			987
Regulatory assets	344			395
Investment in marketable securities and indexed debt	586			478
Indexed debt securities derivative	—			27
Other	180			131
Total deferred tax liabilities	4,776			3,912
Net deferred tax liabilities	$	3,928		$	3,239
Houston Electric
Deferred tax assets:
Regulatory liabilities	$	195		$	205
Benefits and compensation	14			17
Asset retirement obligations	9			7
Other	7			12
Total deferred tax assets	225			241
Deferred tax liabilities:
Property, plant and equipment	1,129			1,087
Regulatory assets	126			177
Total deferred tax liabilities	1,255			1,264
Net deferred tax liabilities	$	1,030		$	1,023
CERC - Continuing Operations
Deferred tax assets:
Benefits and compensation	$	24		$	27
Regulatory liabilities	144			150
Loss and credit carryforwards	183			259
Asset retirement obligations	80			54
Other	23			20
Valuation allowance	(15		)	(18		)
Total deferred tax assets	439			492
Deferred tax liabilities:
Property, plant and equipment	821			773
Regulatory assets	45			41
Other	43			84
Total deferred tax liabilities	909			898
Net deferred tax liabilities	$	470		$	406

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Unaudited Quarterly Information

12 Months Ended

Dec. 31, 2019

Quarterly Financial Information Disclosure [Abstract]

Unaudited Quarterly Information [Text Block]

Unaudited Quarterly Information

Summarized quarterly financial data is as follows:

	Year Ended December 31, 2019
	First Quarter		Second Quarter		Third Quarter			Fourth Quarter
	(in millions, except per share amounts)
CenterPoint Energy
Revenues	$	3,531	$	2,798	$	2,742		$	3,230
Operating income	245		287		392			302
Income available to common shareholders	140		165		241			128
Basic earnings per common share (1)	0.28		0.33		0.48			0.25
Diluted earnings per common share (1)	0.28		0.33		0.47			0.25
Houston Electric
Revenues	686		765		859			680
Operating income	81		169		269			99
Net income	27		100		185			44
CERC
Revenues	2,368		1,342		1,126			1,734
Operating income	196		58		23			73
Net income (loss)	138		28		(7		)	53

	Year Ended December 31, 2018
	First Quarter		Second Quarter			Third Quarter			Fourth Quarter
	(in millions, except per share amounts)
CenterPoint Energy
Revenues	$	3,155	$	2,186		$	2,212		$	3,036
Operating income	251		187			226			167
Income (loss) available to common shareholders	165		(75		)	153			90
Basic earnings (loss) per common share (1)	0.38		(0.17		)	0.35			0.18
Diluted earnings (loss) per common share (1)	0.38		(0.17		)	0.35			0.18
Houston Electric
Revenues	755		854			897			728
Operating income	119		181			227			98
Net income	52		101			143			40
CERC (2)
Revenues	2,400		1,328			1,312			2,303
Operating income (loss)	131		22			(7		)	76
Income (loss) from continuing operations	78		(8		)	(35		)	35
Income (loss) from discontinued operations	52		44			44			(2		)
Net income	130		36			9			33

(1) Quarterly earnings (loss) per common share are based on the weighted average number of shares outstanding during the quarter, and the sum of the quarters may not equal annual earnings (loss) per common share.

(2)

Amounts have been recast to reflect discontinued operations in all periods presented.

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Short Term Borrowings and Long Term Debt

12 Months Ended

Dec. 31, 2019

Debt Disclosure [Abstract]

Short-term Borrowings and Long-term Debt [Text Block]

Short-term Borrowings and Long-term Debt

	December 31, 2019					December 31, 2018
	Long-Term			Current (1)		Long-Term			Current (1)
	(in millions)
CenterPoint Energy:
ZENS due 2029 (2)	$	—		$	19	$	—		$	24
Senior notes 2.50% to 7.08% due 2020 to 2049 (3)	3,728			100		2,000			—
Variable rate term loans 2.275% to 2.56% due 2020 to 2021	1,000			500		—			—
First mortgage bonds 2.19% to 6.72% due 2022 to 2055 (4)	293			—		—			—
Pollution control bonds 5.125% due 2028 (5)	68			—		68			—
Commercial paper (6) (7)	1,901			—		—			—
Unamortized debt issuance costs	(22		)	—		(13		)	—
Unamortized discount and premium, net	(7		)	—		(2		)	—
Houston Electric debt (see details below)	4,719			231		4,258			458
CERC debt (see details below)	2,546			—		2,371			—
Other debt	18			18		—			—
Total CenterPoint Energy debt	$	14,244		$	868	$	8,682		$	482

	December 31, 2019					December 31, 2018
	Long-Term			Current (1)		Long-Term			Current (1)
	(in millions)
Houston Electric:
First mortgage bonds 9.15% due 2021	$	102		$	—	$	102		$	—
General mortgage bonds 1.85% to 6.95% due 2021 to 2049	3,912			—		3,212			—
Restoration Bond Company:
System restoration bonds 4.243% due 2022	134			62		197			59
Bond Company II:
Transition bonds 5.302% due 2019	—			—		—			208
Bond Company III:
Transition bonds 5.234% due 2020	—			29		29			56
Bond Company IV:
Transition bonds 2.161% to 3.028% due 2020 to 2024	613			140		753			135
Unamortized debt issuance costs	(27		)	—		(24		)	—
Unamortized discount and premium, net	(15		)	—		(11		)	—
Total Houston Electric debt	$	4,719		$	231	$	4,258		$	458

	December 31, 2019					December 31, 2018
	Long-Term			Current (1)		Long-Term			Current (1)
	(in millions)
CERC (8):
Senior notes 3.55% to 6.625% due 2021 to 2047	$	2,193		$	—	$	2,193		$	—
Commercial paper (6)	377			—		210			—
Unamortized debt issuance costs	(13		)	—		(15		)	—
Unamortized discount and premium, net	(11		)	—		(17		)	—
Total CERC debt	$	2,546		$	—	$	2,371		$	—

(1) Includes amounts due or exchangeable within one year of the date noted.

(2) CenterPoint Energy’s ZENS obligation is bifurcated into a debt component and an embedded derivative component. For additional information regarding ZENS, see Note 12(b). As ZENS are exchangeable for cash at any time at the option of the holders, these notes are classified as a current portion of long-term debt.

(3) Includes $532 million of senior notes issued by VUHI and $96 million of senior notes issued by Indiana Gas. The senior notes have stated interest rates that range from 3.72% to 7.08%. The senior notes issued by VUHI are guaranteed by SIGECO, Indiana Gas and VEDO. In connection with the Merger, two of CenterPoint Energy’s acquired wholly-owned subsidiaries, VUHI and VCC, made offers to prepay certain outstanding guaranteed senior notes as required pursuant to certain note purchase agreements previously entered into by VUHI and VCC. In turn, VUHI and VCC borrowed $568 million and $191 million, respectively, from CenterPoint Energy to fund note redemptions of senior notes effected pursuant to these prepayment offers. To fund these prepayments and payments of approximately $5 million of accrued interest, CenterPoint Energy issued approximately $764 million of commercial paper.

(4) The first mortgage bonds issued by SIGECO subject SIGECO’s properties to a lien under the related mortgage indenture.

(5) $68 million and $68 million of these series of debt were secured by general mortgage bonds of Houston Electric as of December 31, 2019 and 2018, respectively. These general mortgage bonds are not reflected in Houston Electric’s consolidated financial statements because of the contingent nature of the obligations.

(6) Classified as long-term debt because the termination date of the facility that backstops the commercial paper is more than one year from the date noted.

(7) Commercial paper issued by VUHI has maturities up to 30 days.

(8) Issued by CERC Corp.

Long-term Debt

Debt Retirements. During the year ended December 31, 2019, CenterPoint Energy retired the following debt instruments:

	Retirement Date	Debt Instrument	Aggregate Principal Amount		Interest Rate	Maturity Date
			(in millions)
CenterPoint Energy	December 2019	Guaranteed senior notes	$	3	3.33%	2022
CenterPoint Energy	December 2019	Guaranteed senior notes	6		4.53%	2025

In December 2019, VCC redeemed the aggregate principal amount of its guaranteed senior notes at a redemption price equal to 100% of the principal amount thereof, plus accrued and unpaid interest thereon to but excluding the redemption date, plus the make-whole premium.  The make-whole premium associated with the two redemptions was approximately $1 million and was included in Other Income, net on CenterPoint Energy’s Statements of Consolidated Income.

Debt Transactions. During the year ended December 31, 2019, the following debt instruments were issued or incurred:

	Issuance Date	Debt Instrument	Aggregate Principal Amount		Interest Rate as of December 31, 2019	Maturity Date
			(in millions)
Houston Electric	January 2019	General mortgage bonds	$	700	4.25%	2049
CenterPoint Energy (1)	February 2019	Variable rate term loan	25		2.275%	2020
CenterPoint Energy	May 2019	Variable rate term loan	1,000		2.56%	2021
CenterPoint Energy	August 2019	Unsecured senior notes	500		2.50%	2024
CenterPoint Energy	August 2019	Unsecured senior notes	400		2.95%	2030
CenterPoint Energy	August 2019	Unsecured senior notes	300		3.70%	2049

(1) Draw down by VCC on its variable rate term loan.

Securitization Bonds. As of December 31, 2019, CenterPoint Energy and Houston Electric had special purpose subsidiaries consisting of the Bond Companies, which they consolidate. The 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 transition bonds or system restoration bonds and activities incidental thereto. These Securitization Bonds are payable only through the imposition and collection of “transition” or “system restoration” charges, as defined in the Texas Public Utility Regulatory Act, which are irrevocable, non-bypassable charges to provide recovery of authorized qualified costs. CenterPoint Energy and Houston Electric have no payment obligations in respect of the Securitization Bonds other than to remit the applicable transition or system restoration charges they collect as set forth in servicing agreements among Houston Electric, the Bond Companies and other parties. Each special purpose entity is the sole owner of the right to impose, collect and receive the applicable transition or system restoration charges securing the bonds issued by that entity. Creditors of CenterPoint Energy or Houston Electric have no recourse to any assets or revenues of the Bond Companies (including the transition and system restoration charges), and the holders of Securitization Bonds have no recourse to the assets or revenues of CenterPoint Energy or Houston Electric.

Credit Facilities. The Registrants had the following revolving credit facilities as of December 31, 2019:

Execution  Date	Registrant	Size of Facility		Draw Rate of LIBOR plus (1)	Financial Covenant Limit on Debt for Borrowed Money to Capital Ratio		Debt for Borrowed Money to Capital Ratio as of December 31, 2019 (2)	Termination  Date
		(in millions)
March 3, 2016	CenterPoint Energy	$	3,300	1.500%	65%	(3)	59.0%	March 3, 2022
July 14, 2017	CenterPoint Energy (4)	400		1.125%	65%		51.6%	July 14, 2022
July 14, 2017	CenterPoint Energy (5)	200		1.250%	65%		58.0%	July 14, 2022
March 3, 2016	Houston Electric	300		1.125%	65%	(3)	50.2%	March 3, 2022
March 3, 2016	CERC	900		1.250%	65%		46.4%	March 3, 2022
	Total	$	5,100

(1) Based on credit ratings as of December 31, 2019.

(2) As defined in the revolving credit facility agreement, excluding Securitization Bonds.

(3) For CenterPoint Energy and Houston Electric, the financial covenant limit will temporarily increase from 65% to 70% if Houston Electric experiences damage from a natural disaster in its service territory and CenterPoint Energy certifies to the administrative agent that Houston Electric has incurred system restoration costs reasonably likely to exceed $100 million in a consecutive 12-month period, all or part of which Houston Electric intends to seek to recover through securitization financing. Such temporary increase in the financial covenant would be in effect from the date CenterPoint Energy delivers its certification until the earliest to occur of (i) the completion of the securitization financing, (ii) the first anniversary of CenterPoint Energy’s certification or (iii) the revocation of such certification.

(4) This credit facility was issued by VUHI, is guaranteed by SIGECO, Indiana Gas and VEDO and includes a $10 million swing line sublimit and a $20 million letter of credit sublimit. This credit facility backstops VUHI’s commercial paper program.

(5) This credit facility was issued by VCC, is guaranteed by Vectren and includes a $40 million swing line sublimit and an$80 million letter of credit sublimit.

The Registrants, as well as the subsidiaries of CenterPoint Energy discussed above, were in compliance with all financial debt covenants as of December 31, 2019.

As of December 31, 2019 and 2018, the Registrants had the following revolving credit facilities and utilization of such facilities:

	December 31, 2019								December 31, 2018
Registrant	Loans		Letters of Credit		Commercial Paper		Weighted Average Interest Rate		Loans		Letters of Credit		Commercial Paper		Weighted Average Interest Rate
	(in millions, except weighted average interest rate)
CenterPoint Energy (1)	$	—	$	6	$	1,633	1.95	%	$	—	$	6	$	—	—	%
CenterPoint Energy (2)	—		—		268		2.08	%	—		—		—		—	%
CenterPoint Energy (3)	—		—		—		—	%	—		—		—		—	%
Houston Electric	—		—		—		—	%	—		4		—		—	%
CERC	—		1		377		1.94	%	—		1		210		2.93	%
Total	$	—	$	7	$	2,278			$	—	$	11	$	210

(1) CenterPoint Energy’s outstanding commercial paper generally has maturities of 60 days or less.

(2) This credit facility was issued by VUHI and is guaranteed by SIGECO, Indiana Gas and VEDO.

(3) This credit facility was issued by VCC and is guaranteed by Vectren.

In January 2019, CenterPoint Energy issued the following commercial paper in connection with the closing of the Merger:

Registrant	Issuance Date	Debt Instrument	Aggregate Principal Amount		Weighted Average Interest Rate
			(in millions)
CenterPoint Energy (1) (2)	January 2019	Commercial paper	$	1,660	2.88%

(1) Proceeds from these commercial paper issuances were used to fund a portion of the Merger and to pay related fees and expenses and were contributed to Vectren for its payment of its stub period cash dividend, long-term incentive payments and to fund the repayment of indebtedness of Vectren subsidiaries redeemed at the option of the holder as a result of the closing of the Merger.

(2) The commercial paper notes were issued at various times in January 2019 with maturities up to and including 90 days as of the time of issuance, and, prior to their use as described in connection with the closing of the Merger, the net proceeds of such issuances were invested in short-term investments.

Maturities.  As of December 31, 2019, maturities of long-term debt, capital leases and sinking fund requirements, excluding the ZENS obligation, are as follows:

	CenterPoint Energy (1)		Houston  Electric (1)		CERC		Securitization Bonds
	(in millions)
2020	$	831	$	231	$	—	$	231
2021	2,761		613		593		211
2022	3,302		519		376		219
2023	713		356		300		156
2024	1,184		162		—		162

(1) These maturities include Securitization Bonds principal repayments on scheduled payment dates.

Liens.  As of December 31, 2019, Houston Electric’s assets were subject to liens securing approximately $102 million of first mortgage bonds. Sinking or improvement fund and replacement fund requirements on the first mortgage bonds may be satisfied by certification of property additions. Sinking fund and replacement fund requirements for 2019, 2018 and 2017 have been satisfied by certification of property additions. The replacement fund requirement to be satisfied in 2020 is approximately $295 million, and the sinking fund requirement to be satisfied in 2020 is approximately $1.6 million. CenterPoint Energy expects Houston Electric to meet these 2020 obligations by certification of property additions.

As of December 31, 2019, Houston Electric’s assets were also subject to liens securing approximately $4.0 billion of general mortgage bonds, including approximately $68 million held in trust to secure pollution control bonds for which CenterPoint Energy is obligated. The lien of the general mortgage indenture is junior to that of the mortgage pursuant to which the first mortgage bonds are issued. Houston Electric may issue additional general mortgage bonds on the basis of retired bonds, 70% of property additions or cash deposited with the trustee. Approximately $3.7 billion of additional first mortgage bonds and general mortgage bonds could be issued on the basis of retired bonds and 70% of property additions as of December 31, 2019. Houston Electric has contractually agreed that it will not issue additional first mortgage bonds, subject to certain exceptions.

Other. As of December 31, 2019, certain financial institutions agreed to issue, from time to time, up to $50 million of letters of credit on behalf of Vectren and certain of its subsidiaries in exchange for customary fees. These agreements to issue letters of credit expire on December 31, 2020. As of December 31, 2019, such financial institutions had issued $21 million of letters of credit on behalf of Vectren and certain of its subsidiaries.

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Fair Value Measurements

12 Months Ended

Dec. 31, 2019

Fair Value Disclosures [Abstract]

Fair Value Measurements [Text Block]

Fair Value Measurements

Assets and liabilities that are recorded at fair value in the Registrants’ Consolidated Balance Sheets are categorized based upon the level of judgment associated with the inputs used to measure their value. Hierarchical levels, as defined below and directly related to the amount of subjectivity associated with the inputs to fair valuations of these assets and liabilities, are as follows:

Level 1: Inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date. The types of assets carried at Level 1 fair value generally are exchange-traded derivatives and equity securities, as well as natural gas inventory that has been designated as the hedged item in a fair value hedge.

Level 2: Inputs, other than quoted prices included in Level 1, are observable for the asset or liability, either directly or indirectly. Level 2 inputs include quoted prices for similar instruments in active markets, and inputs other than quoted prices that are observable for the asset or liability. Fair value assets and liabilities that are generally included in this category are derivatives with fair values based on inputs from actively quoted markets. A market approach is utilized to value the Registrants’ Level 2 natural gas derivative assets or liabilities. CenterPoint Energy’s Level 2 indexed debt securities derivative is valued using an option model and a discounted cash flow model, which uses projected dividends on the ZENS-Related Securities and a discount rate as observable inputs.

Level 3: Inputs are unobservable for the asset or liability, and include situations where there is little, if any, market activity for the asset or liability. Unobservable inputs reflect the Registrants’ judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. The Registrants develop these inputs based on the best information available, including the Registrants’ own data. A market approach is utilized to value the Registrants’ Level 3 assets or liabilities. As of December 31, 2019, CenterPoint Energy’s and CERC’s Level 3 assets and liabilities are comprised of physical natural gas forward contracts and options. Level 3 physical natural gas forward contracts and options are valued using a discounted cash flow model which includes illiquid forward price curve locations (ranging from $1.44 to $5.20 per MMBtu for CenterPoint Energy and from $1.44 to $5.20 per MMBtu for CERC) as an unobservable input. CenterPoint Energy’s and CERC’s Level 3 physical natural gas forward contracts and options derivative assets and liabilities consist of both long and short positions (forwards and options). Forward price decreases (increases) as of December 31, 2019 would have resulted in lower (higher) values, respectively, for long forwards and options and higher (lower) values, respectively, for short forwards and options.

The Registrants determine the appropriate level for each financial asset and liability on a quarterly basis and recognize transfers between levels at the end of the reporting period.  

The following tables present information about the Registrants’ assets and liabilities (including derivatives that are presented net) measured at fair value on a recurring basis as of December 31, 2019 and December 31, 2018, and indicate the fair value hierarchy of the valuation techniques utilized by the Registrants to determine such fair value.

CenterPoint Energy

	December 31, 2019											December 31, 2018
	Level 1		Level 2		Level 3		Netting (1)			Total		Level 1		Level 2		Level 3		Netting (1)			Total
Assets	(in millions)
Corporate equities	$	825	$	—	$	—	$	—		$	825	$	542	$	—	$	—	$	—		$	542
Investments, including money market funds (2)	49		—		—		—			49		66		—		—		—			66
Natural gas derivatives (3)(4)	—		250		42		(98		)	194		—		173		47		(82		)	138
Hedged portion of natural gas inventory	—		—		—		—			—		1		—		—		—			1
Total assets	$	874	$	250	$	42	$	(98	)	$	1,068	$	609	$	173	$	47	$	(82	)	$	747

	December 31, 2019											December 31, 2018
	Level 1		Level 2		Level 3		Netting (1)			Total		Level 1		Level 2		Level 3		Netting (1)			Total
Liabilities
Indexed debt securities derivative	$	—	$	893	$	—	$	—		$	893	$	—	$	601	$	—	$	—		$	601
Interest rate derivatives	—		10		—		—			10		24		—		—		—			24
Natural gas derivatives (3)(4)	—		217		24		(161		)	80		—		191		17		(101		)	107
Hedged portion of natural gas inventory	13		—		—		—			13		—		—		—		—			—
Total liabilities	$	13	$	1,120	$	24	$	(161	)	$	996	$	24	$	792	$	17	$	(101	)	$	732

Houston Electric

	December 31, 2019										December 31, 2018
	Level 1		Level 2		Level 3		Netting		Total		Level 1		Level 2		Level 3		Netting		Total
Assets	(in millions)
Investments, including money market funds (2)	$	32	$	—	$	—	$	—	$	32	$	48	$	—	$	—	$	—	$	48
Total assets	$	32	$	—	$	—	$	—	$	32	$	48	$	—	$	—	$	—	$	48
Liabilities
Interest rate derivatives	$	—	$	—	$	—	$	—	$	—	$	24	$	—	$	—	$	—	$	24
Total liabilities	$	—	$	—	$	—	$	—	$	—	$	24	$	—	$	—	$	—	$	24

CERC

	December 31, 2019											December 31, 2018
	Level 1		Level 2		Level 3		Netting (1)			Total		Level 1		Level 2		Level 3		Netting (1)			Total
Assets	(in millions)
Corporate equities	$	2	$	—	$	—	$	—		$	2	$	2	$	—	$	—	$	—		$	2
Investments, including money market funds (2)	11		—		—		—			11		11		—		—		—			11
Natural gas derivatives (3)(4)	—		250		42		(98		)	194		—		173		47		(82		)	138
Hedged portion of natural gas inventory	—		—		—		—			—		1		—		—		—			1
Total assets	$	13	$	250	$	42	$	(98	)	$	207	$	14	$	173	$	47	$	(82	)	$	152
Liabilities
Natural gas derivatives (3)(4)	$	—	$	195	$	24	$	(161	)	$	58	$	—	$	191	$	17	$	(101	)	$	107
Hedged portion of natural gas inventory	13		—		—		—			13		—		—		—		—			—
Total liabilities	$	13	$	195	$	24	$	(161	)	$	71	$	—	$	191	$	17	$	(101	)	$	107

(1) Amounts represent the impact of legally enforceable master netting arrangements that allow CenterPoint Energy and CERC to settle positive and negative positions and also include cash collateral posted with the same counterparties as follows:

	December 31, 2019				December 31, 2018
	CenterPoint Energy		CERC		CenterPoint Energy		CERC
	(in millions)
Cash collateral posted with the same counterparties	$	63	$	63	$	19	$	19

(2) Amounts are included in Prepaid and Other Current Assets and Other Assets in the Consolidated Balance Sheets.

(3) Natural gas derivatives include no material amounts related to physical forward transactions with Enable.

(4) Level 1 natural gas derivatives include exchange-traded derivatives cleared by the CME, which deems that financial instruments cleared by the CME are settled daily in connection with posted cash payments. As a result of this exchange rule, CME-related derivatives are considered to have no fair value at the balance sheet date for financial reporting purposes, and are presented in Level 1 net of posted cash; however, the derivatives remain outstanding and subject to future commodity price fluctuations until they are settled in accordance with their contractual terms. Derivative transactions cleared on exchanges other than the CME (e.g., the Intercontinental Exchange or ICE) continue to be reported on a gross basis.

The following table presents additional information about assets or liabilities, including derivatives that are measured at fair value on a recurring basis for which CenterPoint Energy and CERC have utilized Level 3 inputs to determine fair value:

	Year Ended December 31,
	2019						2018						2017
	CenterPoint Energy			CERC			CenterPoint Energy			CERC			CenterPoint Energy			CERC
	(in millions)
Beginning balance	$	30		$	30		$	(622	)	$	46		$	(704	)	$	13
Total gains	17			17			30			30			96			47
Total settlements	(22		)	(22		)	(39		)	(39		)	(11		)	(11		)
Transfers into Level 3	(1		)	(1		)	5			5			14			14
Transfers out of Level 3 (1)	(6		)	(6		)	656			(12		)	(17		)	(17		)
Ending balance (2)	$	18		$	18		$	30		$	30		$	(622	)	$	46
The amount of total gains for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the reporting date:
	$	12		$	12		$	18		$	18		$	87		$	38

(1) During 2018, CenterPoint Energy transferred its indexed debt securities derivative from Level 3 to Level 2 to reflect changes in the significance of the unobservable inputs used in the valuation.

(2) CenterPoint Energy and CERC did not have significant Level 3 purchases or sales during any of the years ended December 31, 2019, 2018 or 2017.

Estimated Fair Value of Financial Instruments

The fair values of cash and cash equivalents, investments in debt and equity securities classified as “trading” and short-term borrowings are estimated to be approximately equivalent to carrying amounts and have been excluded from the table below. The carrying amounts of non-trading derivative assets and liabilities and CenterPoint Energy’s ZENS indexed debt securities derivative are stated at fair value and are excluded from the table below. The fair value of each debt instrument is determined by multiplying the principal amount of each debt instrument by a combination of historical trading prices and comparable issue data. These liabilities, which are not measured at fair value in the Registrants’ Consolidated Balance Sheets, but for which the fair value is disclosed, would be classified as Level 2 in the fair value hierarchy.

	December 31, 2019						December 31, 2018
	CenterPoint Energy (1)		Houston Electric (1)		CERC		CenterPoint Energy (1)		Houston Electric (1)		CERC
Long-term debt, including current maturities	(in millions)
Carrying amount	$	15,093	$	4,950	$	2,546	$	9,140	$	4,717	$	2,371
Fair value	16,067		5,457		2,803		9,308		4,770		2,488

(1) Includes Securitization Bond debt.

Items measured at Fair Value on a Non-recurring Basis

CenterPoint Energy and CERC recorded a goodwill impairment charge of $48 million related to its Energy Services reporting unit in 2019. See Note 6.

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Related Party Transactions (Houston Electric and CERC)

12 Months Ended

Dec. 31, 2019

Related Party Transactions [Abstract]

Related Party Transactions (Houston Electric and CERC) [Text Block]

Related Party Transactions (Houston Electric and CERC)

Houston Electric and CERC participate in a money pool through which they can borrow or invest on a short-term basis. Funding needs are aggregated and external borrowing or investing is based on the net cash position. The net funding requirements of the money pool are expected to be met with borrowings under CenterPoint Energy’s revolving credit facility or the sale of CenterPoint Energy’s commercial paper. 

The table below summarizes money pool activity:

	December 31, 2019						December 31, 2018
	Houston Electric			CERC			Houston Electric			CERC
	(in millions)
Money pool investments (borrowings) (1)	$	481		$	—		$	(1	)	$	114
Weighted average interest rate	1.98		%	1.98		%	2.42		%	2.42		%

(1) Included in Accounts and notes receivable (payable)–affiliated companies in Houston Electric’s and CERC’s Consolidated Balance Sheets.

Houston Electric and CERC affiliate-related net interest income (expense) were as follows:

	Year Ended December 31,
	2019				2018				2017
	Houston Electric		CERC		Houston Electric		CERC		Houston Electric		CERC
	(in millions)
Interest income (expense), net (1)	$	18	$	4	$	1	$	—	$	2	$	—

(1) Interest income is included in Other, net and interest expense is included in Interest and other finance charges on Houston Electric’s and CERC’s respective Statements of Consolidated Income.

CenterPoint Energy provides some corporate services to Houston Electric and CERC. The costs of services have been charged directly to Houston Electric and CERC using methods that management believes are reasonable. These methods include negotiated usage rates, dedicated asset assignment and proportionate corporate formulas based on operating expenses, assets, gross margin, employees and a composite of assets, gross margin and employees. Houston Electric provides certain services to CERC. These services are billed at actual cost, either directly or as an allocation and include fleet services, shop services, geographic services, surveying and right-of-way services, radio communications, data circuit management and field operations. Additionally, CERC provides certain services to Houston Electric. These services are billed at actual cost, either directly or as an allocation and include line locating and other miscellaneous services. These charges are not necessarily indicative of what would have been incurred had Houston Electric and CERC not been affiliates.

Infrastructure Services provides pipeline construction and repair services to CERC’s NGD. Additionally, CERC, through its subsidiary CES, sells natural gas to Indiana Electric for use in electric generation activities.

Amounts charged for these services are included primarily in Operation and maintenance expenses and amounts billed for natural gas sales are included in Non-utility revenues were as follows:

	Year Ended December 31,
	2019					2018					2017
	Houston Electric			CERC		Houston Electric			CERC		Houston Electric			CERC
	(in millions)
Corporate service charges	$	177		$	141	$	190		$	147	$	188		$	128
Net affiliate service charges (billings)	(8		)	8		(17		)	17		(9		)	9
Pipeline construction and repair service charges (1)	—			4		—			—		—			—
Natural gas sales (2)	—			1		—			—		—			—

(1) Represents charges from Infrastructure Services to CERC’s NGD for the period February 1, 2019 through December 31, 2019.

(2) Represents sales to Indiana Electric from CES for the period February 1, 2019 through December 31, 2019.

The table below presents transactions among Houston Electric, CERC and their parent, Utility Holding.

	Year Ended December 31,
	2019				2018				2017
	Houston Electric		CERC		Houston Electric		CERC		Houston Electric		CERC
	(in millions)
Cash dividends paid to parent	$	376	$	120	$	209	$	360	$	180	$	601
Cash contribution from parent	590		129		200		960		—		38
Capital distribution to parent associated with the Internal Spin (1)	—		28		—		1,473		—		—

(1)

The capital distribution in 2019 associated with the Internal Spin is a result of the return to accrual for the periods of CERC’s ownership during 2018.

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Leases (Policies)

12 Months Ended

Dec. 31, 2019

Leases [Abstract]

Lessee, Leases [Policy Text Block]

The Registrants adopted ASC 842, Leases, and all related amendments on January 1, 2019 using the modified retrospective transition method and elected not to recast comparative periods in the year of adoption as permitted by the standard. There was no adjustment to retained earnings as a result of transition. As a result, disclosures for periods prior to adoption will be presented in accordance with accounting standards in effect for those periods. The Registrants also elected the package of practical expedients permitted under the transition guidance within the new standard, which among other things, allowed them to carry forward the historical lease classification. Additionally, the Registrants elected the practical expedient related to land easements, which allows the carry forward of the accounting treatment for land easements on existing agreements. The total ROU assets obtained in exchange for new operating lease liabilities upon adoption were $30 million, $1 million and $27 million for CenterPoint Energy, Houston Electric and CERC, respectively. The Merger was completed on February 1, 2019, and as such the amounts recorded upon adoption are exclusive of Vectren’s leases.

An arrangement is determined to be a lease at inception based on whether the Registrant has the right to control the use of an identified asset. ROU assets represent the Registrants’ right to use the underlying asset for the lease term and lease liabilities represent the Registrants’ obligation to make lease payments arising from the lease. ROU assets and liabilities are recognized at the lease commencement date based on the present value of lease payments over the lease term, including payments at commencement that depend on an index or rate. Most leases in which the Registrants are the lessee do not have a readily determinable implicit rate, so an incremental borrowing rate, based on the information available at the lease commencement date, is utilized to determine the present value of lease payments. When a secured borrowing rate is not readily available, unsecured borrowing rates are adjusted for the effects of collateral to determine the incremental borrowing rate. Each Registrant uses the implicit rate for agreements in which it is a lessor. Lease expense and lease income are recognized on a straight-line basis over the lease term for operating leases.

The Registrants have lease agreements with lease and non-lease components and have elected the practical expedient to combine lease and non-lease components for certain classes of leases, such as office buildings. For classes of leases in which lease and non-lease components are not combined, consideration is allocated between components based on the stand-alone prices. Sublease income is not significant to the Registrants.

The Registrants’ lease agreements do not contain any material residual value guarantees, material restrictions or material covenants. There are no material lease transactions with related parties. Agreements in which the Registrants are lessors do not include provisions for the lessee to purchase the assets. Because risk is minimal, the Registrants do not take any significant actions to manage risk associated with the residual value of their leased assets.

The Registrants’ lease agreements are primarily equipment and real property leases, including land and office facility leases. The Registrants’ lease terms may include options to extend or terminate a lease when it is reasonably certain that those options will be exercised. Operating lease payments exclude approximately $16 million of legally-binding undiscounted minimum lease payments for leases signed but not yet commenced. The Registrants have elected an accounting policy that exempts leases with terms of one year or less from the recognition requirements of ASC 842.

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Revenue Recognition (Tables)

12 Months Ended

Dec. 31, 2019

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenue [Table Text Block]

The following tables disaggregate revenues by reportable segment and major source:

CenterPoint Energy

	Year Ended December 31, 2019
	Houston Electric T&D (1)			Indiana Electric Integrated (1) (4)		Natural Gas Distribution (1) (4)			Energy  Services (2)			Infrastructure Services (2) (4)			Corporate and Other (2) (4)		Total
	(in millions)
Revenue from contracts	$	2,984		$	523	$	3,680		$	479		$	1,190		$	295	$	9,151
Derivatives income	6			—		2			3,303			—			—		3,311
Other (3)	6			—		1			—			—			5		12
Eliminations	—			—		(40		)	(129		)	(4		)	—		(173		)
Total revenues	$	2,996		$	523	$	3,643		$	3,653		$	1,186		$	300	$	12,301
	Year Ended December 31, 2018
	Houston Electric T&D (1)			Indiana Electric Integrated (1)		Natural Gas Distribution (1)			Energy  Services (2)			Infrastructure Services (2)			Corporate and Other (2)		Total
	(in millions)
Revenue from contracts	$	3,235		$	—	$	3,011		$	493		$	—		$	6	$	6,745
Derivatives income	(2		)	—		(2		)	4,028			—			—		4,024
Other (3)	(1		)	—		(42		)	—			—			9		(34		)
Eliminations	—			—		(36		)	(110		)	—			—		(146		)
Total revenues	$	3,232		$	—	$	2,931		$	4,411		$	—		$	15	$	10,589
	Year Ended December 31, 2017
	Houston Electric T&D (1)			Indiana Electric Integrated (1)		Natural Gas Distribution (1)			Energy Services (2)			Infrastructure Services (2)			Corporate and Other (2)		Total
	(in millions)
Revenue from contracts	$	3,001		$	—	$	2,638		$	480		$	—		$	5	$	6,124
Derivatives income	(1		)	—		—			3,569			—			—		3,568
Other (3)	(3		)	—		1			—			—			9		7
Eliminations	—			—		(33		)	(52		)	—			—		(85		)
Total revenues	$	2,997		$	—	$	2,606		$	3,997		$	—		$	14	$	9,614

(1) Reflected in Utility revenues in the Statements of Consolidated Income.

(2) Reflected in Non-utility revenues in the Statements of Consolidated Income.

(3) Primarily consists of income from ARPs and leases. ARPs are contracts between the utility and its regulators, not between the utility and a customer. The Registrants recognize ARP revenue as other revenues when the regulator-specified conditions for recognition have been met. Upon recovery of ARP revenue through incorporation in rates charged for utility service to customers, ARP revenue is reversed and recorded as revenue from contracts with customers. The recognition of ARP revenues and the reversal of ARP revenues upon recovery through rates charged for utility service may not occur in the same period.

(4) Reflects revenues from Vectren subsidiaries for the period from February 1, 2019 to December 31, 2019.

Houston Electric

	Year Ended December 31,
	2019		2018			2017
	(in millions)
Revenue from contracts	$	2,984	$	3,235		$	3,001
Other (1)	6		(1		)	(3		)
Total revenues	$	2,990	$	3,234		$	2,998

(1) Primarily consists of income from ARPs and leases. ARPs are contracts between the utility and its regulators, not between the utility and a customer. The Registrants recognize ARP revenue as other revenues when the regulator-specified conditions for recognition have been met. Upon recovery of ARP revenue through incorporation in rates charged for utility service to customers, ARP revenue is reversed and recorded as revenue from contracts with customers. The recognition of ARP revenues and the reversal of ARP revenues upon recovery through rates charged for utility service may not occur in the same period.

CERC

	Year Ended December 31, 2019
	Natural Gas Distribution (1)			Energy  Services (2)			Corporate  and Other (2)		Total
	(in millions)
Revenue from contracts	$	2,945		$	480		$	5	$	3,430
Derivatives income	2			3,302			—		3,304
Other (3)	4			—			—		4
Eliminations	(40		)	(128		)	—		(168		)
Total revenues	$	2,911		$	3,654		$	5	$	6,570
	Year Ended December 31, 2018
	Natural Gas Distribution (1)			Energy  Services (2)			Corporate and Other (2)		Total
	(in millions)
Revenue from contracts	$	3,011		$	493		$	1	$	3,505
Derivatives income	(2		)	4,028			—		4,026
Other (3)	(42		)	—			—		(42		)
Eliminations	(36		)	(110		)	—		(146		)
Total revenues	$	2,931		$	4,411		$	1	$	7,343
	Year Ended December 31, 2017
	Natural Gas Distribution (1)			Energy  Services (2)			Corporate and Other (2)		Total
	(in millions)
Revenue from contracts	$	2,638		$	480		$	—	$	3,118
Derivatives income	—			3,569			—		3,569
Other (3)	1			—			—		1
Eliminations	(33		)	(52		)	—		(85		)
Total revenues	$	2,606		$	3,997		$	—	$	6,603

(1) Reflected in Utility revenues in the Statements of Consolidated Income.

(2) Reflected in Non-utility revenues in the Statements of Consolidated Income.

(3)

Primarily consists of income from ARPs and leases. ARPs are contracts between the utility and its regulators, not between the utility and a customer. The Registrants recognize ARP revenue as other revenues when the regulator-specified conditions for recognition have been met. Upon recovery of ARP revenue through incorporation in rates charged for utility service to customers, ARP revenue is reversed and recorded as revenue from contracts with customers. The recognition of ARP revenues and the reversal of ARP revenues upon recovery through rates charged for utility service may not occur in the same period.

Contract with Customer, Asset and Liability [Table Text Block]

The opening and closing balances of accounts receivable, other accrued unbilled revenue, contract assets and contract liabilities from contracts with customers for the year ended December 31, 2019 are as follows:

CenterPoint Energy

	Accounts Receivable		Other Accrued Unbilled Revenues		Contract Assets		Contract Liabilities
	(in millions)
Opening balance as of December 31, 2018 (1)	$	516	$	373	$	—	$	3
Closing balance as of December 31, 2019	800		579		61		34
Increase	$	284	$	206	$	61	$	31

(1) Opening balances related to Vectren are as of February 1, 2019, and are thus excluded from the opening balance as of December 31, 2018.

The amount of revenue recognized in the year ended December 31, 2019 that was included in the opening contract liability was $47 million. The difference between the opening and closing balances of the contract liabilities primarily results from the timing difference between CenterPoint Energy’s performance and the customer’s payment, plus the addition of obligations acquired in the Merger.

Houston Electric

	Accounts Receivable			Other Accrued Unbilled Revenues		Contract Liabilities
	(in millions)
Opening balance as of December 31, 2018	$	234		$	110	$	3
Closing balance as of December 31, 2019	210			117		3
Increase (decrease)	$	(24	)	$	7	$	—

The amount of revenue recognized in the year ended December 31, 2019 that was included in the opening contract liability was $3 million. The difference between the opening and closing balances of the contract liabilities primarily results from the timing difference between Houston Electric’s performance and the customer’s payment.

CERC

	Accounts Receivable		Other Accrued Unbilled Revenues
	(in millions)
Opening balance as of December 31, 2018	$	282	$	263
Closing balance as of December 31, 2019	282		250
Increase (decrease)	$	—	$	(13	)

CERC does not have any opening or closing contract asset or contract liability balances.

Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Table Text Block]

Remaining Performance Obligations (CenterPoint Energy). The table below discloses (1) the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) as of the end of the reporting period for contracts and (2) when CenterPoint Energy expects to recognize this revenue. Such contracts include fixed price contracts and energy performance and sustainable infrastructure services contracts of ESG, which are included in Corporate and Other.

	Rolling 12 Months		Thereafter		Total
	(in millions)
Revenue expected to be recognized on contracts in place as of December 31, 2019:
Infrastructure Services	$	254	$	—	$	254
Corporate and Other	84		752		836
	$	338	$	752	$	1,090

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Goodwill and Other Intangibles (CenterPoint Energy and CERC)

12 Months Ended

Dec. 31, 2019

Goodwill and Intangible Assets Disclosure [Abstract]

Goodwill and Other Intangibles (CenterPoint Energy and CERC) [Text Block]

Goodwill and Other Intangibles (CenterPoint Energy and CERC)

CenterPoint Energy’s goodwill by reportable segment as of December 31, 2018 and changes in the carrying amount of goodwill as of December 31, 2019 are as follows:

	December 31, 2018		Additions (1)		Impairment		December 31, 2019
	(in millions)
Indiana Electric Integrated	$	—	$	1,121	$	—	$	1,121
Natural Gas Distribution	746		2,566		—		3,312
Energy Services (2)	110		—		48		62
Infrastructure Services	—		220		—		220
Corporate and Other	11		438		—		449
Total	$	867	$	4,345	$	48	$	5,164

(1) This represents the allocation of goodwill to reportable segments from the Merger, changes from preliminary amounts previously reported and includes the final determination of fair value for each reportable segment. See Note 4.

(2) Amount presented is net of the accumulated goodwill impairment charge of $252 million recorded in 2012. As of December 31, 2019, CenterPoint Energy and CERC identified a triggering event to perform an interim goodwill impairment test and recognized a goodwill impairment on their Energy Services reporting unit which is included in Goodwill impairment on CenterPoint Energy’s and CERC’s Consolidated Statements of Income.

CERC’s goodwill by reportable segment as of December 31, 2019 and December 31, 2018 is as follows:

	December 31, 2018		Impairment		December 31, 2019
			(in millions)
Natural Gas Distribution	$	746	$	—	$	746
Energy Services (1)	110		48		62
Corporate and Other	11		—		11
Total	$	867	$	48	$	819

(1) Amount presented is net of the accumulated goodwill impairment charge of $252 million recorded in 2012.

CenterPoint Energy and CERC perform goodwill impairment tests at least annually and evaluate goodwill when events or changes in circumstances indicate that its carrying value may not be recoverable. The impairment evaluation for goodwill is performed by comparing the fair value of each reporting unit with the carrying amount of the reporting unit, including goodwill. The reporting units approximate the reportable segments, with the exception of ESG, which is a separate reporting unit but included

in CenterPoint Energy’s Corporate and Other reportable segment. The estimated fair value of a reporting unit is primarily determined based on an income approach or a weighted combination of income and market approaches. If the carrying amount of the reporting unit is in excess of the estimated fair value of the reporting unit, then the excess amount is the impairment charge that should be recorded, not to exceed the carrying amount of goodwill. See Note 2(g) for further discussion.

CenterPoint Energy and CERC performed the annual goodwill impairment test on July 1 of each of 2019 and 2018 and determined that no goodwill impairment charge was required for any reporting unit in its annual test.

In connection with its preparation of financial statements for the year ended December 31, 2019, CenterPoint Energy and CERC, as applicable, identified triggering events for interim goodwill impairment tests at the Infrastructure Services and Energy Services reporting units. Early stage bids received from market participants during the exploration of strategic alternatives for these businesses at year-end indicated that the fair value of each reporting unit was more likely than not below the carrying value. 

On February 3, 2020, CenterPoint Energy, through its subsidiary VUSI, entered into the Securities Purchase Agreement to sell the businesses within its Infrastructure Services reporting unit. Per the Securities Purchase Agreement, VISCO will be converted from a wholly-owned corporation to a limited liability company that is disregarded for federal income tax purposes immediately prior to the closing of the transaction resulting in the sale of membership units at closing.  The sale will be considered an asset sale for tax purposes requiring the net deferred tax liabilities of approximately $123 million within the reporting unit as of December 31, 2019 to be recognized as a benefit to deferred income tax expense by CenterPoint Energy upon closing; therefore, any deferred tax assets and liabilities within the reporting unit are not included in the carrying amount of the assets and liabilities that will be transferred to the buyer. For further information, see Note 23.

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 reporting unit. Per the Equity Purchase Agreement, CES will be converted from a wholly-owned corporation to a limited liability company that is disregarded for federal income tax purposes immediately prior to the closing of the transaction resulting in the sale of membership units at closing. For further information, see Note 23.

The fair value of the Infrastructure Services reporting unit was estimated using a market approach deriving an estimated fair value as of December 31, 2019 based on the economic terms agreed upon within the Securities Purchase Agreement, a Level 2 fair value measurement.  As of December 31, 2019 the fair value of the Infrastructure Services reporting unit exceeded the carrying value (inclusive of deferred income tax liabilities of $123 million) and no impairment loss was recognized.

The fair value of the Energy Services reporting unit was estimated using a combination of the market approach and the income approach as of December 31, 2019, a Level 3 fair value measurement. CenterPoint Energy and CERC utilized the economic indicators of value received by market participants during the exploration of strategic alternatives to inform the fair value of substantially all of the businesses within this reporting unit as of December 31, 2019. Certain assets groups not constituting a business within the reporting unit were valued using an income approach.  CenterPoint Energy and CERC recognized an impairment loss on their Energy Services reporting unit of $48 million, the amount by which the carrying value (inclusive of deferred income tax liabilities of $25 million) exceeded the fair value as of December 31, 2019.

The tables below present information on CenterPoint Energy’s other intangible assets recorded in Intangible assets, net on the Consolidated Balance Sheets and the related amortization expense included in Depreciation and amortization on CenterPoint Energy’s Statements of Consolidated Income, unless otherwise indicated.

	December 31, 2019							December 31, 2018
	Gross Carrying Amount		Accumulated Amortization			Net Balance		Gross Carrying Amount		Accumulated Amortization			Net Balance
	(in millions)
Customer relationships (1)	$	286	$	(43	)	$	243	$	86	$	(27	)	$	59
Covenants not to compete	4		(4		)	—		4		(3		)	1
Trade names (1)	58		(5		)	53		—		—			—
Construction backlog (1) (2)	27		(23		)	4		—		—			—
Operation and maintenance       agreements (1) (2)	12		(1		)	11		—		—			—
Other (1)	24		(14		)	10		16		(11		)	5
Total	$	411	$	(90	)	$	321	$	106	$	(41	)	$	65

(1) The fair value of intangible assets acquired through acquisitions has been finalized. See Note 4.

(2) Amortization expense related to the operation and maintenance agreements and construction backlog is included in Non-utility cost of revenues, including natural gas on CenterPoint Energy’s Statements of Consolidated Income.

	Year Ended December 31,
	2019		2018		2017
	(in millions)
Amortization expense of intangible assets recorded in    Depreciation and amortization (1) (2)	$	25	$	10	$	13
Amortization expense of intangible assets recorded in Non-utility cost of revenues, including natural gas (2)	24		—		—

(1) Includes $17 million for the year ended December 31, 2019 of amortization expense related to intangibles acquired in the Merger.

(2) The fair value of intangible assets, and related amortization assumptions, acquired through acquisitions during the year ended December 31, 2019, has been finalized. See Note 4.

The tables below present information on CERC’s other intangible assets recorded in Other non-current assets on CERC’s Consolidated Balance Sheets and the related amortization expense included in Depreciation and amortization on CERC’s Statements of Consolidated Income.

	December 31, 2019							December 31, 2018
	Gross Carrying Amount		Accumulated Amortization			Net Balance		Gross Carrying Amount		Accumulated Amortization			Net Balance
	(in millions)
Customer relationships	$	86	$	(32	)	$	54	$	86	$	(27	)	$	59
Covenants not to compete	4		(4		)	—		4		(3		)	1
Other	16		(14		)	2		16		(11		)	5
Total	$	106	$	(50	)	$	56	$	106	$	(41	)	$	65

	Year Ended December 31,
	2019		2018		2017
	(in millions)
Amortization expense of intangible assets recorded in    Depreciation and amortization	$	9	$	10	$	13

CenterPoint Energy and CERC estimate that amortization expense of intangible assets with finite lives for the next five years will be as follows:

	Amortization Expense
	CenterPoint Energy		CERC
	(in millions)
2020	$	29	$	6
2021	25		6
2022	25		6
2023	24		5
2024	22		5

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2019

Accounting Policies [Abstract]

Summary of Significant Accounting Policies [Text Block]

Summary of Significant Accounting Policies

(a) Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

(b) Principles of Consolidation

The accounts of the Registrants and their wholly-owned and majority-owned and controlled subsidiaries are included in the consolidated financial statements. All intercompany transactions and balances are eliminated in consolidation, except as described below.

Businesses within the Infrastructure Services reportable segment provide underground pipeline construction and repair services for customers that include NGD utilities. In accordance with consolidation guidance in ASC 980—Regulated Operations, costs incurred by NGD utilities for these pipeline construction and repair services are not eliminated in consolidation when capitalized and included in rate base by the NGD utility. Fees incurred by CenterPoint Energy’s and CERC’s NGD for pipeline construction and repair services that were capitalized totaled $162 million and $20 million, respectively, for the 11 months ended December 31, 2019.

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 is expected to close in the second quarter of 2020. For further information, see Notes 6 and 23.

As of December 31, 2019, CenterPoint Energy and Houston Electric had VIEs consisting of the Bond Companies, which are consolidated. The consolidated VIEs are wholly-owned, bankruptcy remote special purpose entities that were formed solely for the purpose of securitizing transition and system restoration related property. Creditors of CenterPoint Energy and Houston Electric have no recourse to any assets or revenues of the Bond Companies. The bonds issued by these VIEs are payable only from and secured by transition and system restoration property and the bondholders have no recourse to the general credit of CenterPoint Energy or Houston Electric.

(c) Equity and Investments without a Readily Determinable Fair Value (CenterPoint Energy)

CenterPoint Energy generally uses the equity method of accounting for investments in entities in which it has an ownership interest between 20% and 50% and exercises significant influence. CenterPoint Energy also uses the equity method for investments in which it has ownership percentages greater than 50%, when it exercises significant influence, does not have control and is not considered the primary beneficiary, if applicable.

Under the equity method, CenterPoint Energy adjusts its investments each period for contributions made, distributions received, respective shares of comprehensive income and amortization of basis differences, as appropriate. CenterPoint Energy evaluates its equity method investments for impairment when events or changes in circumstances indicate there is a loss in value of the investment that is other than a temporary decline.

CenterPoint Energy considers distributions received from equity method investments which do not exceed cumulative equity in earnings subsequent to the date of investment to be a return on investment and classifies these distributions as operating activities in its Statements of Consolidated Cash Flows. CenterPoint Energy considers distributions received from equity method investments in excess of cumulative equity in earnings subsequent to the date of investment to be a return of investment and classifies these distributions as investing activities in its Statements of Consolidated Cash Flows.

Investments without a readily determinable fair value will be measured at cost, less impairment, plus or minus observable prices changes of an identical or similar investment of the same issuer.

(d) Revenues

The Registrants record revenue for electricity delivery and natural gas sales and services under the accrual method and these revenues are recognized upon delivery to customers. Electricity deliveries not billed by month-end are accrued based on actual AMS data, daily supply volumes and applicable rates. Natural gas sales not billed by month-end are accrued based upon estimated purchased gas volumes, estimated lost and unaccounted for gas and currently effective tariff rates. Revenue for some pipeline construction services are based on the percentage of completion method. For further discussion, see Note 5.

(e) MISO Transactions

Indiana Electric is a member of the MISO. MISO-related purchase and sale transactions are recorded using settlement information provided by the MISO. These purchase and sale transactions are accounted for on at least a net hourly position, meaning net purchases within that interval are recorded on CenterPoint Energy’s Statements of Consolidated Income in Utility natural gas, fuel and purchased power, and net sales within that interval are recorded on CenterPoint Energy’s Statements of Consolidated Income in Utility revenues. On occasion, prior period transactions are resettled outside the routine process due to a change in the MISO’s tariff or a material interpretation thereof. Expenses associated with resettlements are recorded once the resettlement is probable and the resettlement amount can be estimated. Revenues associated with resettlements are recognized when the amount is determinable and collectability is reasonably assured.

(f) Guarantees

CenterPoint Energy recognizes guarantee obligations at fair value. CenterPoint Energy discloses parent company guarantees of a subsidiary’s obligation when that guarantee results in the exposure of a material obligation of the parent company even if the probability of fulfilling such obligation is considered remote. See Note 16(c) and (d).  

(g) Long-lived Assets, Goodwill and Intangibles

The Registrants record property, plant and equipment at historical cost and expense repair and maintenance costs as incurred.

The Registrants periodically evaluate long-lived assets, including property, plant and equipment, and specifically identifiable intangibles subject to amortization, when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable. For rate regulated businesses, recoverability of long-lived assets is assessed by determining if a capital disallowance from a regulator is probable through monitoring the outcome of rate cases and other proceedings. For non-rate regulated businesses, recoverability is assessed based on an estimate of undiscounted cash flows attributable to the assets compared to the carrying value of the assets. As of December 31, 2019, CenterPoint Energy and CERC, as applicable, determined that the carrying value of long-lived and intangible assets associated with the Infrastructure Services and Energy Services reporting units were recoverable based on undiscounted cash flows, considering the likelihood of possible outcomes existing as of that date, including the assessment of the likelihood of a future sale of these assets. No long-lived asset or intangible asset impairments were recorded in 2019, 2018 or 2017.

CenterPoint Energy and CERC perform goodwill impairment tests at least annually and evaluate goodwill when events or changes in circumstances indicate that its carrying value may not be recoverable. Subsequent to the Registrant’s adoption of ASU 2017-04 Simplifying the Test for Goodwill Impairment on January 1, 2018, CenterPoint Energy and CERC recognize a goodwill impairment by the amount a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill within that reporting unit. CenterPoint Energy includes deferred tax assets and liabilities within its reporting unit’s carrying value for the purposes of annual and interim impairment tests, regardless of whether the estimated fair value reflects the disposition of such assets and liabilities. For further information about the goodwill impairment tests during 2019, see Note 6.

(h) Assets Held for Sale and Discontinued Operations

Generally, a long-lived asset to be sold is classified as held for sale in the period in which management, with approval from the Board of Directors, as applicable, commits to a plan to sell and a sale is expected to be completed within one year. The Registrants record assets and liabilities held for sale at the lower of their carrying value or their estimated fair value less cost to sell. If the disposal group reflects a component of a reporting unit and meets the definition of a business, the goodwill within that reporting unit is allocated to the disposal group based on the relative fair value of the components representing a business that will be retained and disposed. Goodwill is not allocated to a portion of a reporting unit that does not meet the definition of a business. A disposal group that meets the held for sale criteria and also represents a strategic shift to the Registrant, is also reflected as discontinued operations on the Statements of Consolidated Income, and prior periods are recast to reflect the earnings or losses from such businesses as income from discontinued operations, net of tax.

(i) Regulatory Assets and Liabilities

The Registrants apply the guidance for accounting for regulated operations to the Houston Electric T&D reportable segment, Indiana Electric Integrated segment and the Natural Gas Distribution reportable segment. The Registrants’ rate-regulated subsidiaries may collect revenues subject to refund pending final determination in rate proceedings. In connection with such revenues, estimated rate refund liabilities are recorded which reflect management’s current judgment of the ultimate outcomes of the proceedings.

The Registrants’ rate-regulated businesses recognize removal costs as a component of depreciation expense in accordance with regulatory treatment. In addition, a portion of the amount of removal costs collected from customers that relate to AROs has been reflected as an asset retirement liability in accordance with accounting guidance for AROs.

For further detail on the Registrants’ regulatory assets and liabilities, see Note 7.

(j) Depreciation and Amortization Expense

The Registrants compute depreciation and amortization using the straight-line method based on economic lives or regulatory-mandated recovery periods. Amortization expense includes amortization of certain regulatory assets and other intangibles.

(k) Capitalization of Interest and AFUDC

The Registrants capitalize interest and AFUDC as a component of projects under construction and amortize it over the assets’ estimated useful lives once the assets are placed in service. AFUDC represents the composite interest cost of borrowed funds and a reasonable return on the equity funds used for construction for subsidiaries that apply the guidance for accounting for regulated operations. Although AFUDC increases both utility plant and earnings, it is realized in cash when the assets are included in rates.

	Year Ended December 31,
	2019						2018						2017
	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC
	(in millions)
Interest and AFUDC debt (1)	$	36	$	8	$	3	$	8	$	6	$	2	$	9	$	6	$	2
AFUDC equity (2)	22		15		3		12		10		2		11		10		1

(1) Included in Interest and other finance charges on the Registrants’ respective Statements of Consolidated Income.

(2) Included in Other Income (Expense) on the Registrants’ respective Statements of Consolidated Income.

(l) Income Taxes

Houston Electric and CERC are included in CenterPoint Energy’s U.S. federal consolidated income tax return. Houston Electric and CERC report their income tax provision on a separate entity basis pursuant to a tax sharing agreement with CenterPoint Energy. Current federal and certain state income taxes are payable to or receivable from CenterPoint Energy.

The Registrants use the asset and liability method of accounting for deferred income taxes. Deferred income tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. A valuation allowance is established against deferred tax

assets for which management believes realization is not considered to be more likely than not. The Registrants recognize interest and penalties as a component of income tax expense (benefit), as applicable, in their respective Statements of Consolidated Income. CenterPoint Energy reports the income tax provision associated with its interest in Enable in income tax expense (benefit) in its Statements of Consolidated Income.

On December 22, 2017, President Trump signed into law comprehensive tax reform legislation informally called the Tax Cuts and Jobs Acts, or TCJA, which resulted in significant changes to federal tax laws effective January 1, 2018. See Note 15 for further discussion of the impacts of tax reform implementation.

To the extent certain EDIT of the Registrants’ rate-regulated subsidiaries may be recoverable or payable through future rates, regulatory assets and liabilities have been recorded, respectively.

The Registrants use the portfolio approach to recognize income tax effects on other comprehensive income from accumulated other comprehensive income.

Investment tax credits are deferred and amortized to income over the approximate lives of the related property.

(m) Accounts Receivable and Allowance for Doubtful Accounts

Accounts receivable are recorded at the invoiced amount and do not bear interest. Management reviews the outstanding accounts receivable, as well as the bad debt write-offs experienced in the past, and establishes an allowance for doubtful accounts. Account balances are charged off against the allowance when management determines it is probable the receivable will not be recovered.

The table below summarizes the Registrants’ provision for doubtful accounts for 2019, 2018 and 2017:

	Year Ended December 31,
	2019						2018						2017
	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC
	(in millions)
Provision for doubtful accounts	$	16	$	—	$	12	$	16	$	—	$	16	$	14	$	1	$	13

(n) Inventory

The Registrants’ inventory consists principally of materials and supplies, and for CERC, natural gas, and for CenterPoint Energy, coal inventory. Materials and supplies are valued at the lower of average cost or market. Materials and supplies are recorded to inventory when purchased and subsequently charged to expense or capitalized to plant when installed. Natural gas inventories of CERC’s Energy Services reportable segment at locations qualifying for and utilizing the fair value hedge accounting election are valued at fair value; inventories at locations not qualifying for or not utilizing the fair value hedge accounting election are valued at the lower of average cost or market. During 2019, 2018 and 2017, CERC recorded write-downs of natural gas inventory to the lower of average cost or market which are disclosed on the respective Statements of Consolidated Cash Flows.

(o) Derivative Instruments

The Registrants are exposed to various market risks. These risks arise from transactions entered into in the normal course of business. The Registrants utilize derivative instruments such as physical forward contracts, swaps and options to mitigate the impact of changes in commodity prices, weather and interest rates on operating results and cash flows. Such derivatives are recognized in the Registrants’ Consolidated Balance Sheets at their fair value unless the Registrant elects the normal purchase and sales exemption for qualified physical transactions. A derivative may be designated as a normal purchase or normal sale if the intent is to physically receive or deliver the product for use or sale in the normal course of business. CenterPoint Energy and CERC have elected to record changes in the fair value of amounts excluded from the assessment of effectiveness immediately in their Statements of Consolidated Income.

CenterPoint Energy has a Risk Oversight Committee composed of corporate and reportable segment officers that oversees commodity price, weather and credit risk activities, including the Registrants’ marketing, risk management services and hedging activities. The committee’s duties are to establish the Registrants’ commodity risk policies, allocate board-approved commercial risk limits, approve the use of new products and commodities, monitor positions and ensure compliance with the Registrants’ risk

management policies and procedures and limits established by CenterPoint Energy’s Board of Directors. The Registrants’ policies prohibit the use of leveraged financial instruments. A leveraged financial instrument, for this purpose, is a transaction involving a derivative whose financial impact will be based on an amount other than the notional amount or volume of the instrument.

(p) Investments in Equity Securities (CenterPoint Energy and CERC)

CenterPoint Energy and CERC report equity securities at estimated fair value in their respective Consolidated Balance Sheets, and any unrealized holding gains and losses are recorded as Other Income (Expense) in their respective Statements of Consolidated Income.

(q) Environmental Costs

The Registrants expense or capitalize environmental expenditures, as appropriate, depending on their future economic benefit. The Registrants expense amounts that relate to an existing condition caused by past operations that do not have future economic benefit. The Registrants record undiscounted liabilities related to these future costs when environmental assessments and/or remediation activities are probable and the costs can be reasonably estimated.

(r) Cash and Cash Equivalents and Restricted Cash

For purposes of reporting cash flows, the Registrants consider cash equivalents to be short-term, highly-liquid investments with maturities of three months or less from the date of purchase. Cash and cash equivalents held by the Bond Companies (VIEs) solely to support servicing the Securitization Bonds as of December 31, 2019 and 2018 are reflected on CenterPoint Energy’s and Houston Electric’s Consolidated Balance Sheets.

In connection with the issuance of Securitization Bonds, CenterPoint Energy and Houston Electric were required to establish restricted cash accounts to collateralize the bonds that were issued in these financing transactions. These restricted cash accounts are not available for withdrawal until the maturity of the bonds and are not included in cash and cash equivalents. For more information on restricted cash see Note 20.

(s) Preferred Stock and Dividends

Preferred stock is evaluated to determine balance sheet classification, and all conversion and redemption features are evaluated for bifurcation treatment. Proceeds received net of issuance costs are recognized on the settlement date. Cash dividends become a liability once declared. Income available to common stockholders is computed by deducting from net income the dividends accumulated and earned during the period on cumulative preferred stock.

(t) Purchase Accounting

The Registrants evaluate acquisitions to determine when a set of acquired activities and assets represent a business. When control of a business is obtained, the Registrants apply the acquisition method of accounting and record the assets acquired, liabilities assumed and any non-controlling interest obtained based on fair value at the acquisition date. The excess of the fair value of purchase consideration over the fair value of the net assets acquired is recorded as goodwill. The results of operations of the acquired business are included in the Registrants’ respective Statements of Consolidated Income beginning on the date of the acquisition.

(u) New Accounting Pronouncements

The following table provides an overview of certain recently adopted or issued accounting pronouncements applicable to all the Registrants, unless otherwise noted.

Recently Adopted Accounting Standards
ASU Number and Name	Description	Date of Adoption	Financial Statement Impact upon Adoption
ASU 2016-02- Leases (Topic 842) and related amendments	ASU 2016-02 provides a comprehensive new lease model that requires lessees to recognize assets and liabilities for most leases and would change certain aspects of lessor accounting. Transition method: modified retrospective	January 1, 2019	The Registrants adopted the standard and recognized a right-of-use asset and lease liability on their statement of financial position with no material impact on their results of operations and cash flows. See Note 22 for more information.

Issued, Not Yet Effective Accounting Standards
ASU Number and Name	Description	Effective Date	Financial Statement Impact upon Adoption
ASU 2016-13- Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments	This standard, including standards amending this standard, requires a new model called CECL to estimate credit losses for (1) financial assets subject to credit losses and measured at amortized cost and (2) certain off-balance sheet credit exposures. Upon initial recognition of the exposure, the CECL model requires an entity to estimate the credit losses expected over the life of an exposure based on historical information, current information and reasonable and supportable forecasts, including estimates of prepayments. Transition method: modified retrospective	January 1, 2020 Early adoption is permitted	The adoption of this standard will result in an immaterial adjustment to the carrying value of the Registrants’ accounts receivable, net. The adoption of this standard will not have a material impact on the Registrants’ financial position, results of operations or cash flows.
ASU 2018-13- Fair Value Measurement (Topic 820): Disclosure Framework-Changes to the Disclosure Requirements for Fair Value Measurement	This standard eliminates, modifies and adds certain disclosure requirements for fair value measurements. Transition method: prospective for additions and one modification and retrospective for all other amendments	Adoption of eliminations and modifications as of September 30, 2018; Additions will be adopted January 1, 2020	The adoption of this standard did not impact the Registrants’ financial position, results of operations or cash flows. Note 10 reflects the disclosures modified upon adoption.
ASU 2018-15-Intangibles-Goodwill and Other- Internal-Use Software (Subtopic 350-40): Customer's Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract	This standard aligns accounting for implementation costs incurred in a cloud computing arrangement that is accounted for as a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. The update also prescribes the balance sheet, income statement and cash flow classification of the capitalized implementation costs and related amortization expense and requires additional quantitative and qualitative disclosures. Transition method: retrospective or prospective	January 1, 2020 Early adoption is permitted	The adoption of this standard will require the Registrants to capitalize certain costs to implement cloud computing arrangements that are accounted for as service contracts within Prepaid expenses and other current assets on the Registrants’ consolidated balance sheets and record the amortization of such assets within Operation and maintenance expenses on the Registrants’ statements of consolidated income. The adoption of this standard will not have a material impact on the Registrants’ financial position, results of operations, cash flows or disclosures.

Management believes that other recently adopted standards and recently issued standards that are not yet effective will not have a material impact on the Registrants’ financial position, results of operations or cash flows upon adoption.

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Commitments and Contingencies (Details)	12 Months Ended
	Dec. 31, 2019 USD ($) site	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)
Purchase Obligations
2020	$ 750,000,000
2021	617,000,000
2022	418,000,000
2023	335,000,000
2024	271,000,000
2025 and beyond	$ 1,888,000,000
Performance Guarantees & Product Warranties [Abstract]
Number of surety bond obligations outstanding	62
Performance guarantee obligations outstanding face amount	$ 565,000,000
Percentage of work yet to be completed on projects with open surety bonds	36.00%
Guarantor Obligations, Maximum Exposure, Undiscounted	$ 499,000,000
Legal, Environmental and Other Matters
Asset Retirement Obligation	$ 539,000,000	$ 258,000,000	$ 281,000,000
Indiana Gas Service Territory [Member]
Legal, Environmental and Other Matters
Environmental remediation number of sites with potential remedial responsibility | site	26
Minnesota and Indiana Gas Service Territories [Member]
Legal, Environmental and Other Matters
Liability recorded for remediation of Minnesota sites	$ 12,000,000
Minnesota and Indiana Gas Service Territories [Member] | Minimum [Member]
Legal, Environmental and Other Matters
Estimated remediation costs for the Minnesota sites	$ 7,000,000
Years to resolve contingency	5
Minnesota and Indiana Gas Service Territories [Member] | Maximum [Member]
Legal, Environmental and Other Matters
Estimated remediation costs for the Minnesota sites	$ 51,000,000
Years to resolve contingency	50
Minnehaha Academy Gas Explosion [Member]
Legal, Environmental and Other Matters
Contested amount of fines imposed	$ 200,000
Indiana Electric [Member]
Legal, Environmental and Other Matters
Asset Retirement Obligation	68,000,000
Indiana Electric [Member] | Minimum [Member]
Legal, Environmental and Other Matters
Estimated capital expenditure to clean ash ponds	60,000,000
Indiana Electric [Member] | Maximum [Member]
Legal, Environmental and Other Matters
Estimated capital expenditure to clean ash ponds	80,000,000
CERC Corp [Member]
Purchase Obligations
2020	533,000,000
2021	432,000,000
2022	242,000,000
2023	182,000,000
2024	174,000,000
2025 and beyond	1,526,000,000
Legal, Environmental and Other Matters
Asset Retirement Obligation	325,000,000	$ 221,000,000	$ 243,000,000
CERC Corp [Member] | Minnesota and Indiana Gas Service Territories [Member]
Legal, Environmental and Other Matters
Liability recorded for remediation of Minnesota sites	7,000,000
CERC Corp [Member] | Minnesota and Indiana Gas Service Territories [Member] | Minimum [Member]
Legal, Environmental and Other Matters
Estimated remediation costs for the Minnesota sites	$ 4,000,000
Years to resolve contingency	30
CERC Corp [Member] | Minnesota and Indiana Gas Service Territories [Member] | Maximum [Member]
Legal, Environmental and Other Matters
Estimated remediation costs for the Minnesota sites	$ 32,000,000
Years to resolve contingency	50
CERC Corp [Member] | Minnehaha Academy Gas Explosion [Member]
Legal, Environmental and Other Matters
Contested amount of fines imposed	$ 200,000
CES natural gas related transactions [Member] | Energy Services [Member]
Performance Guarantees & Product Warranties [Abstract]
Performance guarantee obligations outstanding face amount	1,800,000,000
Guarantor Obligations, Maximum Exposure, Undiscounted	$ 0
Annualized fee received for retained CES obligation guarantees	3.00%
Quarterly increase of fee received for retained CES guarantee exposure	1.00%
Guarantor Obligations, Current Carrying Value	$ 0
CES natural gas related transactions [Member] | Energy Services [Member] | CERC Corp [Member]
Performance Guarantees & Product Warranties [Abstract]
Performance guarantee obligations outstanding face amount	$ 1,800,000,000
Annualized fee received for retained CES obligation guarantees	3.00%
Quarterly increase of fee received for retained CES guarantee exposure	1.00%
Guarantor Obligations, Current Carrying Value	$ 0

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Derivative Instruments Derivatives and Hedging (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019		Dec. 31, 2018	Dec. 31, 2017
Weather hedges term		10 years
Gains (Losses) in Revenue [Member] | Weather Hedge Swaps [Member]
Recognized gain (loss) on weather hedges	[1]	$ 8		$ (4)	$ (1)
2019 to 2020 [Member] | Natural Gas Distribution [Member]
Weather hedge bilateral cap amount		8
2019 to 2020 [Member] | Electric Transmission & Distribution [Member]
Weather hedge bilateral cap amount		7
2019 to 2020 [Member] | Gains (Losses) in Revenue [Member] | Weather Hedge Swaps [Member] | Natural Gas Distribution [Member]
Recognized gain (loss) on weather hedges		2		0	0
2019 to 2020 [Member] | Gains (Losses) in Revenue [Member] | Weather Hedge Swaps [Member] | Electric Transmission & Distribution [Member]
Recognized gain (loss) on weather hedges		3		0	0
2018 to 2019 [Member] | Natural Gas Distribution [Member]
Weather hedge bilateral cap amount		9
2018 to 2019 [Member] | Electric Transmission & Distribution [Member]
Weather hedge bilateral cap amount		8
2018 to 2019 [Member] | Gains (Losses) in Revenue [Member] | Weather Hedge Swaps [Member] | Natural Gas Distribution [Member]
Recognized gain (loss) on weather hedges		0		0	0
2018 to 2019 [Member] | Gains (Losses) in Revenue [Member] | Weather Hedge Swaps [Member] | Electric Transmission & Distribution [Member]
Recognized gain (loss) on weather hedges		3		0	0
2017 to 2018 [Member] | Natural Gas Distribution [Member]
Weather hedge bilateral cap amount		8
2017 to 2018 [Member] | Electric Transmission & Distribution [Member]
Weather hedge bilateral cap amount		9
2017 to 2018 [Member] | Gains (Losses) in Revenue [Member] | Weather Hedge Swaps [Member] | Natural Gas Distribution [Member]
Recognized gain (loss) on weather hedges		0		(2)	0
2017 to 2018 [Member] | Gains (Losses) in Revenue [Member] | Weather Hedge Swaps [Member] | Electric Transmission & Distribution [Member]
Recognized gain (loss) on weather hedges		0		(2)	0
2016 to 2017 [Member] | Electric Transmission & Distribution [Member]
Weather hedge bilateral cap amount		9
2016 to 2017 [Member] | Gains (Losses) in Revenue [Member] | Weather Hedge Swaps [Member] | Electric Transmission & Distribution [Member]
Recognized gain (loss) on weather hedges		$ 0		0	(1)
CERC Corp [Member]
Weather hedges term		10 years
CERC Corp [Member] | Gains (Losses) in Revenue [Member] | Weather Hedge Swaps [Member]
Recognized gain (loss) on weather hedges	[1]	$ 2		(2)	0
CERC Corp [Member] | 2019 to 2020 [Member] | Natural Gas Distribution [Member]
Weather hedge bilateral cap amount		8
CERC Corp [Member] | 2019 to 2020 [Member] | Gains (Losses) in Revenue [Member] | Weather Hedge Swaps [Member] | Natural Gas Distribution [Member]
Recognized gain (loss) on weather hedges		2		0	0
CERC Corp [Member] | 2018 to 2019 [Member] | Natural Gas Distribution [Member]
Weather hedge bilateral cap amount		9
CERC Corp [Member] | 2018 to 2019 [Member] | Gains (Losses) in Revenue [Member] | Weather Hedge Swaps [Member] | Natural Gas Distribution [Member]
Recognized gain (loss) on weather hedges		0		0	0
CERC Corp [Member] | 2017 to 2018 [Member] | Natural Gas Distribution [Member]
Weather hedge bilateral cap amount		8
CERC Corp [Member] | 2017 to 2018 [Member] | Gains (Losses) in Revenue [Member] | Weather Hedge Swaps [Member] | Natural Gas Distribution [Member]
Recognized gain (loss) on weather hedges		0		(2)	$ 0
Not Designated as Hedging Instrument, Economic Hedge [Member] | Interest Rate Contract [Member]
Derivative Liability, Notional Amount		84	[2]	0
Not Designated as Hedging Instrument, Economic Hedge [Member] | Houston Electric [Member] | Interest Rate Contract [Member]
Derivative Liability, Notional Amount		0		0
Cash Flow Hedging [Member] | Interest Rate Contract [Member]
Derivative Liability, Notional Amount		0	[2]	450
Cash Flow Hedging [Member] | Houston Electric [Member] | Interest Rate Contract [Member]
Derivative Liability, Notional Amount		$ 0		$ 450

[1] Weather hedge gains (losses) are recorded in Revenues in the Statements of Consolidated Income.

[2] Relates to interest rate derivative instruments at SIGECO.

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Indexed Debt Securities (ZENS) and Securities Related to ZENS (CenterPoint Energy) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
ZENS-Related Securities
ZENS-Related Securities	$ 540,000,000
Proceeds from sale and maturity of marketable securities	0	$ (398,000,000)	$ 0
Gain (loss) on ZENS-Related Securities	282,000,000	(22,000,000)	7,000,000
ZENS-Related Securities	822,000,000	540,000,000
Debt component of ZENS
Debt Component of ZENS	24,000,000
Distribution to ZENS holders	0	(398,000,000)	0
Debt Component of ZENS	19,000,000	24,000,000
Derivative component of ZENS
Derivative Component of ZENS	601,000,000
Distribution to ZENS holders	0	(398,000,000)	0
Loss (gain) on indexed debt securities	292,000,000	232,000,000	(49,000,000)
Derivative Component of ZENS	$ 893,000,000	$ 601,000,000
AT&T Common [Member]
Indexed Debt Securities [Line Items]
Balance of investment owned (in shares)	10,212,945	10,212,945
Charter Common [Member]
Indexed Debt Securities [Line Items]
Balance of investment owned (in shares)	872,503	872,912
ZENS-Related Securities [Member]
ZENS-Related Securities
ZENS-Related Securities	$ 540,000,000	$ 960,000,000	953,000,000
Proceeds from sale and maturity of marketable securities		(398,000,000)
Gain (loss) on ZENS-Related Securities	282,000,000	(22,000,000)	7,000,000
ZENS-Related Securities	822,000,000	540,000,000	960,000,000
Debt Component Of ZENS [Member]
Debt component of ZENS
Debt Component of ZENS	24,000,000	122,000,000	114,000,000
Accretion of debt component of ZENS	17,000,000	21,000,000	27,000,000
2 % interest paid	(17,000,000)	(17,000,000)	(17,000,000)
Distribution to ZENS holders	(5,000,000)	(102,000,000)	(2,000,000)
Debt Component of ZENS	19,000,000	24,000,000	122,000,000
Derivative component of ZENS
Distribution to ZENS holders	(5,000,000)	(102,000,000)	(2,000,000)
Derivative Component Of ZENS [Member]
Debt component of ZENS
Distribution to ZENS holders	0	(46,000,000)	0
Derivative component of ZENS
Derivative Component of ZENS	601,000,000	668,000,000	717,000,000
Distribution to ZENS holders	0	(46,000,000)	0
Loss (gain) on indexed debt securities	292,000,000	(21,000,000)	(49,000,000)
Derivative Component of ZENS	893,000,000	$ 601,000,000	$ 668,000,000
Subordinated Debt ZENS Member
Indexed Debt Securities [Line Items]
Principal amount of debt issued	1,000,000,000.0
Outstanding debt balance	$ 828,000,000
Subordinated note cash exchangeable percentage of fair value	95.00%
ZENS annual interest rate	2.00%
Target annual yield on referenced shares before increase or decrease of principal amount of subordinated note	2.309%
Contingent principal amount of indexed debt securities issued by CenterPoint Energy in September 1999 and outstanding and exchangeable	$ 75,000,000
The cash exchange amount from referenced shares per $1,000 face amount of individual notes	944
Face amount of each indexed debt security notes issued by CenterPoint Energy in September 1999	$ 1,000
Subordinated Debt ZENS Member | AT&T Common [Member]
Indexed Debt Securities [Line Items]
Number of shares referenced in exchangeable subordinated note	0.7185	0.7185
Subordinated Debt ZENS Member | Charter Common [Member]
Indexed Debt Securities [Line Items]
Number of shares referenced in exchangeable subordinated note	0.061382	0.061382

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Reportable Segments Revenues by Products and Services (Details) - USD ($) $ in Millions	3 Months Ended												12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018		Sep. 30, 2018		Jun. 30, 2018		Mar. 31, 2018		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Revenues by Products and Services:
Revenues	$ 3,230	$ 2,742	$ 2,798	$ 3,531	$ 3,036		$ 2,212		$ 2,186		$ 3,155		$ 12,301	$ 10,589	$ 9,614
Electric Delivery [Member]
Revenues by Products and Services:
Revenues													3,019	3,232	2,997
Retail Electric Sales [Member]
Revenues by Products and Services:
Revenues													486
Wholesale Electric Sales [Member]
Revenues by Products and Services:
Revenues													14
Retail Gas Sales [Member]
Revenues by Products and Services:
Revenues													4,802	4,161	3,634
Wholesale Gas Sales [Member]
Revenues by Products and Services:
Revenues													2,312	3,008	2,811
Gas Transportation and Processing [Member]
Revenues by Products and Services:
Revenues													33	32	29
Infrastructure Services [Member]
Revenues by Products and Services:
Revenues													1,186
Energy Products and Services [Member]
Revenues by Products and Services:
Revenues													449	156	143
Houston Electric [Member]
Revenues by Products and Services:
Revenues	680	859	765	686	728		897		854		755		2,990	3,234	2,998
Houston Electric [Member] | Electric Delivery [Member]
Revenues by Products and Services:
Revenues													2,990	3,234	2,998
Houston Electric [Member] | Retail Gas Sales [Member]
Revenues by Products and Services:
Revenues													0	0	0
Houston Electric [Member] | Wholesale Gas Sales [Member]
Revenues by Products and Services:
Revenues													0	0	0
Houston Electric [Member] | Gas Transportation and Processing [Member]
Revenues by Products and Services:
Revenues													0	0	0
Houston Electric [Member] | Energy Products and Services [Member]
Revenues by Products and Services:
Revenues													0	0	0
CERC Corp [Member]
Revenues by Products and Services:
Revenues	$ 1,734	$ 1,126	$ 1,342	$ 2,368	$ 2,303	[1]	$ 1,312	[1]	$ 1,328	[1]	$ 2,400	[1]	6,570	7,343	6,603
CERC Corp [Member] | Electric Delivery [Member]
Revenues by Products and Services:
Revenues													0	0	0
CERC Corp [Member] | Retail Gas Sales [Member]
Revenues by Products and Services:
Revenues													4,070	4,161	3,634
CERC Corp [Member] | Wholesale Gas Sales [Member]
Revenues by Products and Services:
Revenues													2,313	3,008	2,811
CERC Corp [Member] | Gas Transportation and Processing [Member]
Revenues by Products and Services:
Revenues													33	32	29
CERC Corp [Member] | Energy Products and Services [Member]
Revenues by Products and Services:
Revenues													$ 154	$ 142	$ 129

[1] Amounts have been recast to reflect discontinued operations in all periods presented.

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Background (Details) $ in Millions				12 Months Ended
		Feb. 03, 2020 USD ($)	Feb. 01, 2019 USD ($)	Dec. 31, 2019 USD ($) state shares	Dec. 31, 2018
Vectren [Member]
Cash paid to acquire Vectren | $			$ 6,000	$ 5,982
Enable Midstream Partners [Member]
Ownership percentage of equity method investment	[1],[2]			53.70%	54.00%
Enable Midstream Partners [Member] | Series A Preferred Units [Member]
Preferred units held | shares				14,520,000
Enable GP, LLC [Member]
Management rights ownership percentage				50.00%
Incentive distribution right				40.00%
CERC Corp [Member] | Natural Gas Distribution [Member]
Number of states in which entity operates | state				6
CERC Corp [Member] | Energy Services [Member]
Number of states in which entity operates | state				30
CenterPoint Energy [Member] | Enable GP, LLC [Member]
Management rights ownership percentage	[3],[4]			50.00%
Incentive distribution right	[4],[5]			40.00%
Subsequent Event [Member] | Infrastructure Services [Member]
Sales price of outstanding equity interests | $		$ 850

[1] Excludes the Enable Series A Preferred Units owned by CenterPoint Energy.

[2] Prior to the Internal Spin completed in September 2018, CenterPoint Energy’s investment in Enable’s common units, excluding the Enable Series A Preferred Units held directly by CenterPoint Energy, was held indirectly through CERC.

[3] As of December 31, 2019, Enable is controlled jointly by CenterPoint Energy and OGE. Sale of CenterPoint Energy’s or OGE’s ownership interests in Enable GP to a third party is subject to mutual rights of first offer and first refusal, and CenterPoint Energy is not permitted to dispose of less than all of its interest in Enable GP.

[4] Held indirectly through CNP Midstream.

[5] Enable is expected to pay a minimum quarterly distribution of $0.2875 per common unit on its outstanding common units to the extent it has sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to Enable GP and its affiliates, within 60 days after the end of each quarter. If cash distributions to Enable’s unitholders exceed $0.330625 per common unit in any quarter, Enable GP will receive increasing percentages or incentive distributions rights, up to 50%, of the cash Enable distributes in excess of that amount. In certain circumstances Enable GP will have the right to reset the minimum quarterly distribution and the target distribution levels at which the incentive distributions receive increasing percentages to higher levels based on Enable’s cash distributions at the time of the exercise of this reset election. To date, no incentive distributions have been made.

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Supplemental Disclosure of Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2019

Supplemental Cash Flow Elements [Abstract]

Schedule of Cash Flow, Supplemental Disclosures [Table Text Block]

The tables below provide supplemental disclosure of cash flow information:

	2019						2018						2017
	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC
	(in millions)
Cash Payments/Receipts:
Interest, net of capitalized interest	$	436	$	229	$	109	$	363	$	200	$	105	$	378	$	205	$	116
Income taxes (refunds), net	155		87		7		89		154		3		15		76		4
Non-cash transactions:
Accounts payable related to capital expenditures	236		117		86		201		124		80		144		104		56
Capital distribution associated with the Internal Spin (1)	—		—		28		—		—		1,473		—		—		—
ROU assets obtained in exchange for lease liabilities (2)	44		1		29		—		—		—		—		—		—

(1) The capital distribution in 2019 associated with the Internal Spin is a result of the return to accrual for the periods of CERC’s ownership during 2018.

(2) Includes the transition impact of adoption of ASU 2016-02 Leases as of January 1, 2019. The Registrants elected not to recast comparative periods in the year of adoption as permitted by the standard.

The table below provides a reconciliation of cash, cash equivalents and restricted cash reported in the Consolidated Balance Sheets to the amount reported in the Statements of Consolidated Cash Flows:

	December 31, 2019						December 31, 2018
	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC
	(in millions)
Cash and cash equivalents (1) (2)	$	241	$	216	$	2	$	4,231	$	335	$	14
Restricted cash included in Prepaid expenses and other current assets	30		19		—		46		34		11
Restricted cash included in Other	—		—		—		1		1		—
Total cash, cash equivalents and restricted cash shown in Statements of Consolidated Cash Flows	$	271	$	235	$	2	$	4,278	$	370	$	25

(1) CenterPoint Energy’s Cash and cash equivalents as of December 31, 2018 included $3.9 billion of temporary investments resulting from the Merger financings. CenterPoint Energy recorded interest income of $22 million, $28 million and $2 million for the years ended December 31, 2019, 2018 and 2017, respectively, in Other, net on CenterPoint Energy’s Statements of Consolidated Income. See Notes 13 and 14 for further details related to the Merger financings.

(2)

Houston Electric’s Cash and cash equivalents as of December 31, 2019 and 2018 included $216 million and $335 million, respectively, of cash related to the Bond Companies. Houston Electric recorded interest income of $9 million, $4 million and $2 million for the years ended December 31, 2019, 2018 and 2017, respectively, in Other, net on Houston Electric’s Statement of Consolidated Inc

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2019

Commitments and Contingencies Disclosure [Abstract]

Long-term Purchase Commitment [Table Text Block]

As of December 31, 2019, minimum purchase obligations are approximately:

	CenterPoint Energy		CERC
	(in millions)
2020	$	750	$	533
2021	617		432
2022	418		242
2023	335		182
2024	271		174
2025 and beyond	1,888		1,526

Schedule of Environmental Loss Contingencies by Site [Table Text Block]

Total costs that may be incurred in connection with addressing these sites cannot be determined at this time. The estimated accrued costs are limited to CenterPoint Energy’s and CERC’s share of the remediation efforts and are therefore net of exposures of other PRPs. The estimated range of possible remediation costs for the sites for which CenterPoint Energy and CERC believe they may have responsibility was based on remediation continuing for the minimum time frame given in the table below.

	December 31, 2019
	CenterPoint Energy		CERC
	(in millions, except years)
Amount accrued for remediation	$	12	$	7
Minimum estimated remediation costs	7		4
Maximum estimated remediation costs	51		32
Minimum years of remediation	5		30
Maximum years of remediation	50		50