UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

______________________

Form 10-K



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

	FOR THE FISCAL YEAR ENDED DECEMBER 31, ~~2015~~2018
OR
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

	FOR THE TRANSITION PERIOD FROM TO

~~Commission File Number 1-31447~~

~~______________________~~

~~CenterPoint Energy, Inc.~~

~~(Exact name of registrant as specified in its charter)~~



~~Texas~~	~~74-0694415~~
(	Registrant, State or ~~other jurisdiction~~Other Jurisdiction of ~~incorporation~~Incorporation or ~~organization)~~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 ~~(Address and zip code of principal executive offices)~~	~~(713) 207-1111~~ ~~(Registrant’s telephone number, including area code)~~

~~Securities registered pursuant to Section 12(b) of the Act:~~


	(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	Name of each exchange on which registered
CenterPoint Energy, Inc.	Common Stock, $0.01 par value	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	New York Stock Exchange
CenterPoint Energy Houston Electric, LLC	9.15% First Mortgage Bonds due 2021	New York Stock Exchange
CenterPoint Energy Houston Electric, LLC	6.95% General Mortgage Bonds due 2033	New York Stock Exchange
CenterPoint Energy Resources Corp.	6.625% Senior Notes due 2037	New York Stock Exchange

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

~~Securities registered pursuant to Section 12(g) of the Act:~~

~~None~~

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



CenterPoint Energy, Inc.	Yes þ	þNo 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	oNo 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	þNo 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 ~~and posted on its corporate Web site, if any,~~ every Interactive Data File required to be submitted ~~and posted~~ pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit ~~and post~~ such files).



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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o



CenterPoint Energy, Inc.	þ
CenterPoint Energy Houston Electric, LLC	þ
CenterPoint Energy Resources Corp.	þ

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



~~Large accelerated filer~~ þ	~~Accelerated filer~~ o	~~Non-accelerated filer~~ o	~~Smaller reporting company~~ o
	Large accelerated filer	~~(Do not check if a smaller~~Accelerated filer	Non-accelerated filer	Smaller reporting ~~company)~~company	Emerging growth company
CenterPoint Energy, Inc.	þ	o	o	o	o
CenterPoint Energy Houston Electric, LLC	o	o	þ	o	o
CenterPoint Energy Resources Corp.	o	o	þ	o	o

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

The aggregate market ~~value~~values of the voting stock held by non-affiliates of ~~CenterPoint Energy, Inc. (CenterPoint Energy) was~~ ~~$8,146,639,191~~the Registrants as of June ~~30, 2015, using the definition of beneficial ownership contained in Rule 13d-3 promulgated pursuant to the Securities Exchange Act of 1934 and excluding shares held by directors and executive officers. As of~~ ~~February 12, 2016, CenterPoint Energy had~~ ~~430,271,749~~ ~~shares of Common Stock outstanding. Excluded from~~29, 2018 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)		$11,873,304,802
CenterPoint Energy Houston Electric, LLC		None
CenterPoint Energy Resources Corp.		None

Indicate the number of shares outstanding of ~~Common Stock outstanding are~~each of the issuers’ classes of common stock as of February 12, 2019:



CenterPoint Energy, Inc.	501,206,304 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 ~~as treasury stock.~~Houston Electric, LLC and CenterPoint Energy Resources Corp. meet the conditions set forth in general instruction I(1)(a) and (b) of Form 10-K and are therefore filing this Form 10-K with the reduced disclosure format specified in General Instruction I(2) of Form 10-K.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the definitive proxy statement relating to the ~~2016~~2019 Annual Meeting of Shareholders of CenterPoint Energy, which will be filed with the Securities and Exchange Commission within 120 days of December 31, ~~2015~~,2018, 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	1819
Item 1B.	Unresolved Staff Comments	3945
Item 2.	Properties	3945
Item 3.	Legal Proceedings	4046
Item 4.	Mine Safety Disclosures	4046
PART II
Item 5.	Market for Registrants’ Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	4146
Item 6.	Selected Financial Data	4247
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	4347
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	7381
Item 8.	Financial Statements and Supplementary Data	7584
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	~~122~~164
Item 9A.	Controls and Procedures	~~122~~165
Item 9B.	Other Information	~~124~~167
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	~~124~~167
Item 11.	Executive Compensation	~~124~~167
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	~~125~~167
Item 13.	Certain Relationships and Related Transactions, and Director Independence	~~125~~168
Item 14.	Principal Accounting Fees and Services	~~125~~168
PART IV
Item 15.	Exhibits and Financial Statement Schedules	~~125~~169
Item 16.	Form 10-K Summary	169



GLOSSARY
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
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
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
CCR		Coal Combustion Residuals
CEA		Commodities Exchange Act of 1936
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
Charter merger		Merger of Charter Communications, Inc. and Time Warner Cable Inc.
CIP		Conservation Improvement Program
CME		Chicago Mercantile Exchange
CNG		Compressed natural gas
CNP Midstream		CenterPoint Energy Midstream, Inc., a wholly-owned subsidiary of CenterPoint Energy
COLI		Corporate-owned life insurance



GLOSSARY
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
EDIT		Excess deferred income taxes
EECR		Energy Efficiency Cost Recovery
EECRF		Energy Efficiency Cost Recovery Factor
EGT		Enable Gas Transmission, LLC
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
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
FERC		Federal Energy Regulatory Commission
Fitch		Fitch Ratings, Inc.
FRP		Formula Rate Plan
Gas Daily		Platts gas daily indices
GenOn		GenOn Energy, Inc.
GHG		Greenhouse gases
GMES		Government Mandated Expenditure Surcharge
GRIP		Gas Reliability Infrastructure Program
GWh		Gigawatt-hours
Houston Electric		CenterPoint Energy Houston Electric, LLC and its subsidiaries
HVAC		Heating, ventilation and air conditioning
IBEW		International Brotherhood of Electrical Workers
ICA		Interstate Commerce Act of 1887
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

iii



GLOSSARY
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
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
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
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



GLOSSARY
PBRC		Performance Based Rate Change
PHMSA		Pipeline and Hazardous Materials Safety Administration
PLCA		Pipeline Contractors Association
PRPs		Potentially responsible parties
PUCT		Public Utility Commission of Texas
Railroad Commission		Railroad Commission of Texas
RCRA		Resource Conservation and Recovery Act of 1976
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
RRA		Rate Regulation Adjustment
RRI		Reliant Resources, Inc.
RSP		Rate Stabilization Plan
SEC		Securities and Exchange Commission
SESH		Southeast Supply Header, LLC
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
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
TDSIC		Transmission, Distribution and Storage System Improvement Charge
TDU		Transmission and distribution utility
Time		Time Inc.
Time Common		Time common stock
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



GLOSSARY
Utility Holding		Utility Holding, LLC, a wholly-owned subsidiary of CenterPoint Energy
VaR		Value at Risk
Vectren		Vectren Corporation
VEDO		Vectren Energy Delivery of Ohio, Inc., a wholly-owned subsidiary of Vectren
VIE		Variable interest entity
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
WACC		Weighted average cost of capital
ZENS		2.0% Zero-Premium Exchangeable Subordinated Notes due 2029
ZENS-Related Securities		As of December 31, 2018, consisted of AT&T Common and Charter Common and as of December 31, 2017, consisted of Charter Common, Time Common and TW 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

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

From time to time wethe Registrants make statements concerning ~~our~~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 ~~our~~ forward-looking statements by the words “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecast,” “goal,” “intend,” “may,” “objective,” “plan,” “potential,” “predict,” “projection,” “should,” “target,” “will” or other similar words.

WeThe Registrants have based ~~our~~their forward-looking statements on ~~our~~ management’s beliefs and assumptions based on information reasonably available to ~~our~~ management at the time the statements are made. WeThe Registrants caution you that assumptions, beliefs, expectations, intentions and projections about future events may and often do vary materially from actual results. Therefore, wethe Registrants cannot assure you that actual results will not differ materially from those expressed or implied by ~~our~~the Registrants’ forward-looking statements. In this Form 10-K, unless context requires otherwise, the terms “our,” “we” and “us” are used as abbreviated references to CenterPoint Energy, Inc. together with its consolidated subsidiaries, including Houston Electric, CERC, and, as of February 1, 2019, Vectren and its subsidiaries.

Some of the factors that could cause actual results to differ from those expressed or implied by ~~our~~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 wethe Registrants undertake no obligation to update or revise any forward-looking statements.

iivii

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, which, as of February 1, 2019, includes Vectren and its subsidiaries.

OUR BUSINESS

Overview

~~We are~~CenterPoint Energy is a public utility holding ~~company. Our~~company and owns interests in Enable. As of December 31, 2018, CenterPoint Energy’s operating subsidiaries, ~~own~~Houston Electric and ~~operate~~CERC Corp., owned and operated electric transmission and distribution ~~facilities~~ and natural gas distribution facilities and ~~own interests in Enable Midstream Partners, LP (Enable) as described below. Our indirect wholly-owned subsidiaries include:~~

CenterPoint Energy Houston Electric, LLC (CenterPoint Houston), which engages in the electric transmission and distribution business in the Texas Gulf Coast area that includes the city of Houston; and

~~CenterPoint Energy Resources Corp. (CERC Corp. and, together with its subsidiaries, CERC), which owns and operates~~supplied natural gas ~~distribution systems (NGD). A wholly-owned subsidiary of CERC Corp. offers variable and fixed-price physical natural gas supplies primarily~~ to commercial and industrial customers and electric and natural gas utilities.

CenterPoint Energy’s simplified corporate structure as of December 31, 2018 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.


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


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

(5)

As of December 31, 2018, CNP Midstream owned approximately 54.0% 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.

CenterPoint Energy’s service territories as of December 31, 2018 are depicted below:

As of December 31, ~~2015, CERC Corp. also owned approximately 55.4% of the limited partner interests in Enable, which owns, operates and develops natural gas and crude oil infrastructure assets.~~2018, reportable segments by Registrant are as follows:



	Electric Transmission & Distribution	Natural Gas Distribution	Energy Services	Midstream Investments	Other Operations
CenterPoint Energy	X	X	X	X	X
Houston Electric	X
CERC		X	X		X

~~Our reportable business~~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, are Electric Transmission & Distribution, Natural Gas Distribution, Energy Services, Midstream Investments and Other Operations. Substantially all of our former Interstate Pipelines business segment and Field Services business segment were contributedsee Note 19 to ~~Enable in May 2013. As a result, these business segments did not report operating results during 2014 or 2015.~~the consolidated financial statements. From time to time, we consider the acquisition or the disposition of assets or businesses.

~~Our~~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 further discussion of the Merger and a description of Vectren’s businesses, see Note 4 to the consolidated financial statements.

Following the Merger, CenterPoint Energy’s simplified corporate structure as of February 1, 2019 is shown below:

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 ~~Securities~~SEC. The SEC maintains an Internet website that contains reports, proxy and ~~Exchange Commission (SEC).~~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.

Electric Transmission & Distribution (CenterPoint Energy and Houston Electric)

~~CenterPoint~~ 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. ~~Neither CenterPoint~~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 ~~nor any other subsidiary of CenterPoint Energy makes~~Electric does not make direct retail or wholesale sales of electric energy or ~~owns~~own or ~~operates~~operate any electric generating facilities.

Houston Electric’s distribution service territory as of December 31, 2018 is depicted below:

Electric Transmission

On behalf of ~~retail electric providers (REPs), CenterPoint~~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 ~~kilovolts (kV)~~kV in locations throughout ~~CenterPoint Houston’s~~Houston Electric’s certificated service territory. ~~CenterPoint~~ Houston Electric constructs and maintains transmission facilities and provides transmission services under tariffs approved by the ~~Public Utility Commission of Texas (Texas Utility Commission).~~PUCT.

~~Electric Distribution~~

In the Electric Reliability Council of Texas, Inc. (ERCOT), end users purchase their electricity directly from certificated REPs. CenterPoint Houston delivers electricity for REPs in its certificated service area by carrying lower-voltage power from the substation to the retail electric customer. CenterPoint Houston’s distribution network receives electricity from the transmission grid through power distribution substations and delivers electricity to end users through distribution feeders. CenterPoint Houston’s operations include construction and maintenance of distribution facilities, metering services, outage response services and call center operations. CenterPoint Houston provides distribution services under tariffs approved by the Texas Utility Commission. Texas Utility Commission 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 Texas Utility Commission.

~~ERCOT Market Framework~~

CenterPoint Houston is a member of ERCOT. Within ERCOT, prices for wholesale generation and retail electric sales are unregulated, but services provided by transmission and distribution companies, such as CenterPoint Houston, are regulated by the Texas Utility Commission. ERCOT serves as the regional reliability coordinating council for member electric power systems in most of Texas. ERCOT membership is open to consumer groups, investor and municipally-owned electric utilities, rural electric cooperatives, independent generators, power marketers, river authorities and REPs. The ERCOT market includes most of the State of Texas, other than a portion of the panhandle, portions of the eastern part of the state bordering Arkansas and Louisiana and the area in and around El Paso. 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 included available generating capacity of over 77,000 megawatts (MW) as of December 31, 2015. Currently, there are only limited direct current interconnections between the ERCOT market and other power markets in the United States and Mexico.

The ERCOT market operates under the reliability standards set by the North American Electric Reliability Corporation (NERC) and approved by the Federal Energy Regulatory Commission (FERC). Within ERCOT, these reliability standards are administered by the Texas Reliability Entity (TRE). The Texas Utility Commission has primary jurisdiction over the ERCOT market to ensure the adequacy and reliability of electricity supply across the state’s main interconnected power transmission grid. The ERCOT independent system operator (ERCOT ISO)ISO is responsible for operating the bulk electric power supply system in the ERCOT market. ~~Its responsibilities include ensuring that electricity production and delivery are accurately accounted for among the generation resources and wholesale buyers and sellers.~~

~~CenterPoint Houston’s electric~~Houston Electric’s transmission business, along with those of other owners of transmission facilities in Texas, supports the operation of the ERCOT ISO. The transmission business has planning, design, construction, operation and maintenance responsibility for the portion of the transmission grid and for the load-serving substations it owns, primarily within its certificated area. CenterPoint 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.

~~Restructuring of the Texas~~ Electric ~~Market~~Distribution

In ~~1999,~~ERCOT, end users purchase their electricity directly from certificated REPs. Houston Electric’s distribution network receives electricity from the ~~Texas legislature adopted~~transmission grid through power distribution substations and delivers electricity for REPs in its certificated service area by carrying lower-voltage power from the Texas Electric Choice Plan (Texas electric restructuring law). Pursuant to that legislation, integrated electric utilities operating within ERCOT were required to unbundle their integrated operations into separate retail sales, power generation and transmission and distribution companies. The legislation provided for a transition period to movesubstation to the ~~new~~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 ~~structure~~protocols govern the commercial operations of distribution companies and ~~provided a mechanism~~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. The consolidated special purpose subsidiaries are wholly-owned, bankruptcy remote entities that were formed solely for the ~~formerly integrated electric utilities to recover stranded~~purpose of purchasing and ~~certain other costs resulting from the~~owning transition ~~to competition. Those costs were recoverable after approval by the Texas Utility Commission either~~or system restoration property through the issuance of securitization bonds or through the implementation of a competition transition charge as a rider to the utility’s tariff. CenterPoint Houston’s integrated utility business was restructured in accordance with the Texas electric restructuring lawSecuritization Bonds, and its generating stations were sold to third parties. Ultimately CenterPoint Houston was authorized to recover a total of approximately $5 billion in stranded costs, other charges and related interest. Most of that amount was recovered through the issuance of transition bonds by special purpose subsidiaries of CenterPoint Houston.conducting activities incidental thereto. The ~~transition bonds~~

Securitization Bonds are repaid through charges imposed on customers in ~~CenterPoint Houston’s~~Houston Electric’s service territory. AsFor further discussion of the Securitization Bonds and the outstanding balances as of December 31, ~~2015, approximately $2.3 billion aggregate principal amount of transition bonds were outstanding.~~2018 and 2017, see Note 14 to the consolidated financial statements.

Customers

~~CenterPoint~~ Houston Electric serves nearly all of the Houston/Galveston metropolitan area. At December 31, ~~2015, CenterPoint Houston’s~~2018, Houston Electric’s customers consisted of approximately 6965 REPs, which sell electricity to ~~over 2.3~~approximately 2.5 million metered customers in ~~CenterPoint Houston’s~~Houston

Electric’s certificated service area, and municipalities, electric cooperatives and other distribution companies located outside ~~CenterPoint Houston’s~~Houston Electric’s certificated service area. Each REP is licensed by, and must meet minimum creditworthiness criteria established by, the ~~Texas Utility Commission.~~

Sales to REPs that are affiliates of NRG Energy, Inc. (NRG) represented approximately 35%, 37% and 38% of CenterPoint Houston’s transmission and distribution revenues in 2015, 2014 and 2013, respectively. Sales to REPs that are affiliates of Energy Future Holdings Corp. (Energy Future Holdings) represented approximately 10% of CenterPoint Houston’s transmission and distribution revenues in each of 2015, 2014 and 2013. CenterPoint Houston’s aggregate billed receivables balance from REPs as of December 31, 2015 was $195 million. Approximately 34% and 11% of this amount was owed by affiliates of NRG and Energy Future Holdings, respectively. CenterPointPUCT. 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, 2018:

~~Advanced Metering System and Distribution~~



	Residential	Commercial/ Industrial	Total Customers
Texas Gulf Coast	2,198,225	287,145	2,485,370

Utility Technology

Houston Electric’s Smart Grid ~~Automation (Intelligent Grid)~~

~~In May 2012, CenterPoint Houston substantially completed the deployment of an advanced metering system (AMS), having installed approximately 2.2 million smart meters. To recover the cost~~is comprised of the AMS, ~~the Texas Utility Commission approved a monthly surcharge payable by REPs, initially over 12 years~~IG, ADMS and later reduced to six years as a result of U.S. Department of Energy (DOE) grant funds. The surcharge expired in 2015 for residential customers and is set to expire in 2016 to 2017 for non-residential customers. The surcharge amounts and duration are subject to adjustment in future proceedings to reflect actual costs incurred and to address required changes in scope.

~~CenterPoint~~private telecommunications network. Since 2009, Houston is also pursuing deployment of an electric distribution grid automation strategy that involves the implementation of an “Intelligent Grid” (IG) which would provide on-demand data and information about the status of facilities on its system. We expect to include the costs of the deployment in future rate proceedings before the Texas Utility Commission.

In October 2009, the DOE selected CenterPoint Houston for a $200 million grant to help fund its AMS and IG projects. CenterPoint Houston received substantially all of the $200 million of grant funding from the DOE by 2011 and used $150 million of it to accelerate completion of its deployment ofElectric has deployed fully operational advanced meters to ~~2012. CenterPoint Houston used the other $50 million from the grant for an initial deployment of an IG that covers approximately 12%~~virtually all of its approximately 2.5 million metered customers, automated 57 substations, installed 1,525 IG Switching Devices on more than 350 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 ~~territory. The DOE-funded portion~~reliability and restoration, enhance the consumer experience, support the growth of renewable energy and help the ~~IG project was substantially completed in 2015, and the capital portion of the IG project subject to partial funding~~environment by ~~the DOE cost approximately $140 million.~~reducing carbon emissions.

Competition

There are no other electric transmission and distribution utilities in ~~CenterPoint Houston’s~~Houston Electric’s service area. ~~In order for~~For another provider of transmission and distribution services to provide such services in ~~CenterPoint Houston’s~~Houston Electric’s territory, it would be required to obtain a certificate of convenience and necessity from the ~~Texas Utility Commission~~PUCT and, depending on the location of the facilities, may also be required to obtain franchises from one or more municipalities. ~~We know~~Houston Electric is not aware of noany other party intending to enter this business in ~~CenterPoint Houston’s~~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 ~~CenterPoint Houston’s electric~~Houston Electric’s distribution services but has not been a significant factor to date.

Seasonality

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

Properties

All of ~~CenterPoint Houston’s~~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 ~~CenterPoint Houston’s~~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 ~~CenterPoint~~ 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.

~~As of December 31, 2015, CenterPoint Houston had approximately $2.1 billion aggregate principal amount of general mortgage bonds~~For information related to debt outstanding under the Mortgage and General Mortgage, ~~including (a) approximately $56 million held in trust~~see Note 14 to ~~secure pollution control bonds that are not reflected on our~~the consolidated financial statements because CenterPoint Houston is both the obligor on the bonds and the current owner of the bonds, and (b) approximately $118 million held in trust to secure pollution control bonds for which we are obligated. Additionally, as of December 31, 2015, CenterPoint Houston had approximately $102 million aggregate principal amount of first mortgage bonds outstanding under the Mortgage. CenterPoint Houston may issue additional general mortgage bonds on the basis of retired bonds, 70% of property additions or cash deposited with the trustee. Approximately $4.2 billion of additional first mortgage bonds and general mortgage bonds in the aggregate could be issued on the basis of retired bonds and 70% of property additions as of December 31, 2015. However, CenterPoint Houston has contractually agreed that it will not issue additional first mortgage bonds, subject to certain exceptions.statements.

Electric Lines - ~~Overhead.~~Transmission and Distribution. As of December 31, ~~2015, CenterPoint~~2018, Houston Electric owned ~~28,474 pole miles of overhead~~and operated the following electric transmission and distribution lines and 3,723 circuit miles of overhead transmission lines, including 325 circuit miles operated at 69,000 volts, 2,181 circuit miles operated at 138,000 volts and 1,217 circuit miles operated at 345,000 volts.lines:

~~Electric Lines - Underground.~~ As of December 31, 2015, CenterPoint Houston owned 23,120 circuit miles of underground distribution lines and 26 circuit miles of underground transmission lines, including two circuit miles operated at 69,000 volts and 24 circuit miles operated at 138,000 volts.



	Circuit Miles
Description	Overhead Lines	Underground Lines
Transmission lines - 69 kV	266	2
Transmission lines - 138 kV	2,207	24
Transmission lines - 345 kV	1,336	—
Total transmission lines	3,809	26
Distribution lines	29,094	25,255

Substations. As of December 31, ~~2015, CenterPoint~~2018, Houston Electric owned ~~232~~235 major substation sites having a total installed rated transformer capacity of ~~58,674~~68,338 megavolt amperes.

Service Centers. ~~CenterPoint~~As of December 31, 2018, Houston ~~operates 14~~Electric operated 15 regional service centers located on a total of ~~292~~332 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

~~CenterPoint~~ Houston Electric holds non-exclusive franchises from ~~the~~certain incorporated municipalities in its service territory. In exchange for the payment of fees, these franchises give ~~CenterPoint~~ 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.

Natural Gas Distribution (CenterPoint Energy and CERC)

~~CERC Corp.’s~~CERC’s NGD engages in regulated intrastate natural gas sales to, and natural gas transportation and storage for, approximately ~~3.4~~3.5 million residential, commercial, industrial and transportation customers in Arkansas, Louisiana, Minnesota, Mississippi, Oklahoma and Texas. The largest metropolitan areas served in each state by CERC’s NGD are Houston, Texas; Minneapolis, Minnesota; Little Rock, Arkansas; Shreveport, Louisiana; Biloxi, Mississippi; and Lawton, Oklahoma. ~~In 2015, approximately 39% of NGD’s total throughput was to residential customers and approximately 61% was to commercial and industrial and transportation customers.~~

~~The table below reflects the number of natural gas distribution customers by state as of December 31, 2015:~~

Residential
Commercial/
Industrial
Total Customers
Arkansas 379,319
48,128
427,447
Louisiana 229,873
16,917
246,790
Minnesota 770,891
69,381
840,272
Mississippi 112,140
12,536
124,676
Oklahoma 89,756
10,789
100,545
Texas 1,567,866
96,170
1,664,036
Total NGD 3,149,845
253,921
3,403,766

CERC’s NGD also provides unregulated services in Minnesota consisting of residential appliance repair and maintenance services along with ~~heating, ventilating~~HVAC equipment sales.

CERC’s NGD’s service territory as of December 31, 2018 is depicted below:

Customers

In 2018, approximately 40% of CERC’s NGD’s total throughput was to residential customers and ~~air conditioning (HVAC) equipment sales.~~approximately 60% was to commercial and industrial and transportation customers. The table below reflects the number of CERC’s NGD customers by state as of December 31, 2018:



	Residential	Commercial/ Industrial	Total Customers
Arkansas	377,290	47,963	425,253
Louisiana	230,234	16,648	246,882
Minnesota	797,907	70,604	868,511
Mississippi	114,694	12,628	127,322
Oklahoma	88,685	10,783	99,468
Texas	1,637,467	101,407	1,738,874
Total NGD	3,246,277	260,033	3,506,310

Seasonality

The demand for ~~intrastate~~ natural gas sales to residential customers and natural gas sales and transportation for commercial and industrial customers is seasonal. In ~~2015,~~2018, approximately 68% of ~~the~~CERC’s NGD’s total throughput ~~of NGD’s business~~ 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 ~~2015,~~2018, CERC’s NGD purchased virtually all of its natural gas supply pursuant to contracts with remaining terms varying from a few months to four years. Major suppliers in ~~2015~~2018 included BP Energy Company/BP Canada Energy Marketing (18.4% of supply volumes), Tenaska Marketing Ventures (14.5%), Sequent Energy Management (9.0%), ConocoPhillips Company (7.0%), Kinder Morgan Tejas Pipeline/Kinder Morgan Texas Pipeline (6.3%), Twin Eagle Resource Management (3.4%), CenterPoint Energy Services (3.2%), Mieco (3.1%), Oneok Energy Services (2.9%), and Trailstone NA Logistics (2.3%).the following:



Supplier		Percent of Supply Volumes
Tenaska Marketing Ventures		18.5%
Macquarie Energy, LLC		13.1%
BP Energy Company/BP Canada Energy Marketing		10.3%
Sequent Energy Management, LP		7.6%
Kinder Morgan Tejas Pipeline/Kinder Morgan Texas Pipeline		5.6%
Mieco, Inc.		5.4%
Spire Marketing, Inc.		3.4%
United Energy Trading, LLC		3.1%
CIMA Energy, LTD		3.0%
Koch Energy Services, LLC		2.6%

Numerous other suppliers provided the remaining ~~30%~~27.4% of CERC’s NGD’s natural gas supply requirements. CERC’s NGD transports its natural gas supplies through various intrastate and interstate pipelines under contracts with remaining terms, including extensions, varying from one to ~~eight~~fifteen years. CERC’s NGD anticipates that these gas supply and transportation contracts will be renewed or replaced prior to their expiration.

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 ~~our~~CERC’s NGD’s physical gas suppliers. Its gas supply plans generally call for 50–75% of winter supplies to be stabilized in some fashion.

The regulations of the states in which CERC’s NGD operates allow it 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 its customers under purchased gas adjustment provisions in its 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.

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 and~~weather. CERC’s NGD may also supplement contracted supplies and storage from time to time with stored ~~liquefied natural gas~~LNG and propane-air plant production.

CERC’s NGD owns and operates an underground natural gas storage facility with a capacity of 7.0 ~~billion cubic feet (Bcf).~~Bcf. It has a working capacity of 2.0 Bcf available for use during the heating season and a maximum daily withdrawal rate of 50 ~~million cubic feet (MMcf).~~MMcf. It also owns eight propane-air plants with a total production rate of 180,000 ~~Dekatherms (DTH)~~Dth per day and on-site storage facilities for 12 million gallons of propane (1.0 Bcf natural gas equivalent). It owns a ~~liquefied natural gas~~LNG plant facility with a 12 million-gallon ~~liquefied natural gas~~LNG storage tank (1.0 Bcf natural gas equivalent) and a production rate of 72,000 ~~DTH~~Dth per day.

On an ongoing basis, CERC’s NGD enters into contracts to provide sufficient supplies and pipeline capacity to meet its 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.

CERC’s NGD has ~~entered into various asset management agreements (AMAs)~~AMAs associated with its utility distribution service in Arkansas, Louisiana, Mississippi, Oklahoma and Texas. In March 2018, CERC’s NGD’s third-party AMAs in Arkansas, Louisiana and Oklahoma expired, and CERC’s NGD entered into new AMAs with CES effective April 1, 2018 in these states. The AMAs have varying terms, the longest of which expires in 2021. Pursuant to the provisions of the agreements, CERC’s NGD sells natural gas and agrees to repurchase an equivalent amount of natural gas during the winter heating seasons at the same cost. Generally, ~~these~~ AMAs are contracts between 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, CERC’s NGD ~~agreed~~agrees to release transportation and storage capacity to other parties to manage natural gas storage, supply and delivery arrangements for CERC’s NGD and to use the released capacity for other purposes when it is not needed for CERC’s NGD. CERC’s NGD is compensated by the asset manager through payments made over the life of the ~~agreements based in part on the results of~~AMAs. CERC’s NGD has an obligation to purchase its winter storage requirements that have been released to the asset optimization. NGD has received approval from the state regulatory commissions in Arkansas, Louisiana, Mississippi and Oklahoma to retain a share of the AMA proceeds. The agreements have varying terms, the longest of which expires in 2019.manager under these AMAs.

Assets

As of December 31, ~~2015,~~2018, CERC’s NGD owned approximately ~~74,000~~76,000 linear miles of natural gas distribution mains, varying in size from one-half inch to 24 inches in diameter. Generally, in each of the cities, towns and rural areas served by CERC’s NGD, it owns the underground gas mains and service lines, metering and regulating equipment located on customers’ premises and the district regulating equipment necessary for pressure maintenance. With a few exceptions, the measuring stations at which CERC’s NGD receives gas are owned, operated and maintained by others, and its distribution facilities begin at the outlet of the measuring equipment. These facilities, including odorizing equipment, are usually located on land owned by suppliers.

Competition

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 CERC’s NGD’s facilities and market and 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 ~~CenterPoint Energy Services, Inc. (CES)~~CES and its subsidiary, ~~CenterPoint~~CEIP, collectively, Energy ~~Intrastate Pipelines, LLC (CEIP).~~Services.

In ~~2015,~~2018, CES marketed approximately ~~618~~1,355 Bcf of natural gas (including approximately 33 Bcf to affiliates) and provided related energy services and transportation to approximately ~~18,000~~30,000 customers ~~(including approximately 9 Bcf to affiliates)~~ in 23over 30 states. CES customers vary in size from small commercial customers to large utility companies. Not included in the 2018 customer count are approximately 65,000 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.

Energy Services’ service territory as of December 31, 2018 is depicted below:

In 2017, CES completed the acquisition of AEM, providing CES with a portfolio of industrial and large commercial customers complementary to CES’s existing customer base and strategically aligned storage and transportation assets. For further information related to this acquisition, see Note 4 to the consolidated financial statements.

CES offers a variety of natural gas management services to gas utilities, large industrial customers, electric generators, smaller commercial and industrial customers, municipalities, educational institutions, government facilities and hospitals. These services include load forecasting, supply acquisition, daily swing volume management, invoice consolidation, storage asset management, firm and interruptible transportation administration and forward price management. CES also offers a portfolio of physical delivery services designed to meet customers’ supply and ~~price~~ risk management needs. These ~~customers are served directly,~~services include (1) through CEIP, permanent pipeline connections through interconnects with various interstate and intrastate pipeline companies and ~~portably,~~(2) through ~~our mobile energy solutions business.~~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 in an effort to balance daily and monthly purchases and sales obligations. Natural gas supply and transportation capabilities are leveraged through contracts for ancillary services including physical storage and other balancing arrangements.

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

~~Our~~CenterPoint Energy’s and CERC’s risk control policy, which is overseen by ~~our~~CenterPoint Energy’s Risk Oversight Committee, ~~(ROC),~~ 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 ~~proprietary or~~ speculative commodity trading. ~~The VaR limit within which~~ CES currently operates within a ~~$4 million maximum~~VaR limit set by ~~the~~CenterPoint Energy’s Board of Directors, is 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. ~~In 2015, CES’~~Should CES exceed this VaR ~~averaged $0.2 million with a high~~limit, management is required to notify CenterPoint Energy’s Board of ~~$1.0 million.~~Directors.

Assets

As of December 31, 2018, CEIP ~~owns~~owned and ~~operates~~operated over 200 miles of intrastate pipeline in Louisiana and Texas. In addition, CES leases transportation capacity on various interstate and intrastate pipelines and storage to service its shippers and end users.

Competition

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

Midstream Investments (CenterPoint Energy)

~~In May 2013, we,~~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 ~~Energy Corp. (OGE) and affiliates~~as of ~~ArcLight Capital Partners, LLC (ArcLight), formed Enable, initially a private limited partnership.~~December 31, 2018.

On ~~April 16, 2014, Enable~~September 4, 2018, CERC completed the Internal Spin of its initial public offering (IPO) of 28,750,000 common units at a price of $20.00 per unit, which included 3,750,000 common units sold by ArcLight pursuant to an over-allotment option that was fully exercised by the underwriters. Enable received $464 million in net proceeds from the sale of the units, after deducting underwriting fees, structuring fees and other offering costs. In connection with Enable’s IPO, a portion of our common units were converted into subordinated units. As of December 31, 2015, CERC Corp. held an approximate 55.4% limited partner interestequity investment in Enable, ~~(consisting~~consisting of ~~94,151,707~~Enable common units and 139,704,916 subordinated units) and OGE held an approximate 26.3% limited partner interest in Enable (consisting of 42,832,291 common units and 68,150,514 subordinated units). Sales of more than 5% of the aggregate of the common units and subordinated units we own in Enable or sales by OGE of more than 5% of the aggregate of the common units and subordinated units it owns in Enable are subject to mutual rights of first offer and first refusal.

Enable is controlled jointly by CERC Corp. and OGE as each own 50% of the management rights in the general partner of Enable. Sale of our ownership interests in Enable’s general partner to anyone other than an affiliate prior to May 1, 2016 is prohibited by Enable’s general partner’s limited liability company agreement. Sale of our or OGE’s ownership interests in Enable’s general partner to a third party is subject to mutual rights of first offer and first refusal, and we are not permitted to dispose of less than all of our interest in Enable’s general partner.

As of December 31, 2015, CERC Corp. and OGE also own a 40% and 60% interest, respectively, in the incentive distribution rights held by the general partner of Enable. Enable is expected to pay a minimum quarterly distribution of $0.2875 per unit on its outstanding units to the extent it has sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to its general partner and its affiliates, within 45 days after the end of each quarter. If cash distributions to Enable’s unitholders exceed $0.330625 per unit in any quarter, the general partner will receive increasing percentages or incentive distributions rights, up to 50%, of the cash Enable distributes in excess of that amount. In certain circumstances the general partner of Enable will have the right to reset the minimum quarterly distribution and the target distribution levels at which the incentive distributions receive increasing percentages to higher levels based on Enable’s cash distributions at the time of the exercise of this reset election.

On January 28, 2016, we entered into a purchase agreement with Enable pursuant to which we agreed to purchase in a private placement (Private Placement) an aggregate of 14,520,000 10% Series A Fixed-to-Floating Non-Cumulative Redeemable Perpetual Preferred Units representing limited partner interests in Enable ~~(Series A Preferred Units) for a cash purchase price~~GP, to CenterPoint Energy. For further discussion of ~~$25.00 per Series A Preferred Unit. The Private Placement closed on February 18, 2016. In connection with~~ the ~~Private Placement, Enable redeemed approximately $363 million of notes scheduled~~Internal Spin, see Note 11 to ~~mature in 2017 payable to a wholly-owned subsidiary of CERC Corp. We used~~ the ~~proceeds from this redemption for our investment in the Series A Preferred Units.~~consolidated financial statements.

~~Our investment in Enable is accounted for on an equity basis. Equity earnings associated with our interest in Enable are reported under the Midstream Investments segment.~~

Enable. Enable ~~was formed to own, operate~~owns, operates and ~~develop~~develops midstream energy infrastructure assets strategically located natural gas and crude oil infrastructure assets. Enable serves current and emerging production areas in the United States, including several unconventional shale resource plays and local and regional end-user markets in the United States.to serve its customers. Enable’s assets and operations are organized into two reportable segments: (i) gathering and processing ~~which~~and (ii) transportation and storage. Enable’s gathering and processing segment primarily provides natural gas gathering and processing ~~and fractionation services and crude oil gathering for~~to its producer customers and ~~(ii)~~crude oil, condensate and produced water gathering services to its producer and refiner customers. Enable’s transportation and storage ~~which~~segment provides interstate and intrastate natural gas pipeline transportation and storage services primarily to ~~natural gas producers, utilities~~its producer, power plant, local distribution company and industrial end-user customers.

Enable’s natural gas gathering and processing assets are located in Oklahoma,Texas, Arkansas, Louisiana and Mississippi and serve natural gas production in the Anadarko, Arkoma and Ark-La-Tex basins. Enable also owns a crude oil gathering business located in North Dakota that commenced initial operations in November 2013 to serve shale development in the Bakken Shale formation of the Williston Basin. Enable’s natural gas transportation and storage assets extend from western Oklahoma and the Texas Panhandle to Alabama and from Louisiana to Illinois.

As of December 31, 2015, Enable’s portfolio of energy infrastructure assets included approximately 12,400 miles of gathering pipelines, 13 major processing plants with approximately 2.3 Bcf per day of processing capacity and 2.3 Bcf per day of treating capacity, approximately 7,900 miles of interstate pipelines (including Southeast Supply Header, LLC (SESH)), approximately 2,200 miles of intrastate pipelines and eight storage facilities providing approximately 85.0 Bcf of storage capacity.

Enable’s Gathering and Processing segment.Enable ~~provides~~owns and operates substantial natural gas and crude oil gathering ~~compression, treating, dehydration, processing~~ and natural gas ~~liquids (NGLs) fractionation for producers who are active~~processing assets in ~~the areas in which Enable operates. Eight of~~five states. Enable’s gathering and processing ~~plants in the Anadarko basin are interconnected through its super-header system. Enable has configured this system to facilitate the flow~~operations consist primarily of natural gas ~~from western Oklahoma~~gathering and processing assets serving the ~~Wheeler County area~~Anadarko, Arkoma and Ark-La-Tex Basins and crude oil gathering assets serving the Anadarko and Williston Basins. 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 Texas Panhandle to the Bradley, Cox City, Thomas, McClure, Calumet, Clinton, South Canadian and Wheeler processing plants. Enable is constructing two cryogenic processing facilities to connect to its super-header systembasins in ~~Grady County, Oklahoma and Garvin County, Oklahoma,~~ which are expected to add 400 MMcf per day of natural gas processing capacity. The first of the two new plants (the Bradley II Plant, formerly referred to as the Grady County Plant) is a 200 MMcf per day plant that is expected to be completed in the second quarter of 2016. The second plant (the Wildhorse Plant) is a 200 MMcf per day plant that is expected to be completed in late 2017. Enable’s super-header system is intended to optimize the economics of its natural gas processing and to improve system utilization and reliability.it operates.

Enable’s gathering and processing systems compete with gatherers and processors of all types and sizes, including those affiliated with various producers, other major pipeline companies and various independent midstream entities. In the process of selling NGLs, Enable competes against other natural gas processors extracting and selling NGLs. Enable’s primary competitors are ~~master limited partnerships~~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 ~~provides fee-based~~owns and operates interstate and intrastate natural gas transportation and storage ~~services~~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 ~~were designed and built to serve large~~transport natural gas ~~and electric utility companies in its~~from areas of ~~operation. Enable owns~~production and ~~operates approximately 7,900 miles (including SESH) of interstate~~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 ~~pipelines with average firm contracted capacity of 7.19 Bcf per day (excluding SESH), for the year ended December 31, 2015. In addition, Enable owns~~ and operates approximately 2,200 miles of intrastate transportation pipelines with average aggregate throughput of 1.84 trillion British thermal units per day for the year ended December 31, 2015. Enablestorage assets also ~~owns eight~~provide facilities where natural gas storage facilities with approximately 85.0 Bcf of aggregate capacity and approximately 1.9 Bcf per day of aggregate daily deliverability as of December 31, 2015. In addition, Enable owns an 8% contractual interest in Gulf South’s Bistineau storage facility located in Bienville Parish, Louisiana, with 8.0 Bcf of capacity and 100 MMcf per day of deliverability as of December 31, 2015. Enable also contracts on a firm basis for 3.3 Bcf of high deliverability salt dome storage capacity from Cardinal in the Perryville and Arcadia natural gas storage fields. Enable’s storage operations are located in Louisiana, Oklahoma and Illinois.can be stored by customers.

Enable’s interstate and intrastate pipelines compete with a variety of other interstate and intrastate ~~pipelines. Enable’s intrastate pipeline system competes with numerous interstate~~pipelines across its operating areas in providing transportation and ~~intrastate pipelines,~~storage services, including several ofpipelines with which it interconnects. Enable’s management views the ~~interconnected pipelines discussed above, as well as other natural gas storage facilities. The~~ principal elements of competition among pipelines ~~are~~as rates, terms of service, ~~and~~ flexibility and reliability of service.

~~SESH.~~ ~~SESH owns an approximately 290-mile interstate pipeline that runs from Perryville, Louisiana~~For information related to ~~southwestern Alabama near~~CenterPoint Energy’s equity method investment in Enable, see Note 2(c) and Note 11 to the Gulf Coast. The pipeline was placed into service in the third quarter of 2008. The rates charged by SESH for interstate transportation services are regulated by the FERC. During the year ended December 31, 2015, an average of approximately 1.5 Bcf per day was transported on this system.consolidated financial statements.

On each of May 1, 2013 and May 30, 2014, we contributed a 24.95% interest in SESH to Enable. On June 30, 2015, we contributed our remaining 0.1% interest in SESH to Enable. The remaining 50% of SESH is owned by Spectra Energy Partners, LP.

Other Operations (CenterPoint Energy and CERC)

~~Our~~CenterPoint Energy’s Other Operations ~~business~~reportable segment includes office buildings and other real estate used ~~in our~~for business operations, home repair protection plans through a third party and other corporate support operations that support ~~all of our~~CenterPoint Energy’s business operations. CERC’s Other Operations reportable segment includes unallocated corporate costs and inter-segment eliminations.

~~Financial Information About Segments~~Vectren Operations

Upon closing of the Merger on February 1, 2019, Vectren became a direct wholly-owned subsidiary of CenterPoint Energy. Vectren, through its wholly-owned subsidiary, VUHI, holds three public utilities, SIGECO, Indiana Gas and VEDO, which provide electric and natural gas utility services. SIGECO provides energy delivery services to electric and natural gas customers located near Evansville in southwestern Indiana and is a transmission-owning member of MISO, a regional transmission organization. SIGECO also owns and operates 1,252 MWs of electric generation assets to serve its electric customers and optimizes those assets in the wholesale power market. Indiana Gas provides energy delivery services to natural gas customers located in central and southern Indiana. VEDO provides energy delivery services to natural gas customers located near Dayton in west-central Ohio. Vectren’s utility service territory is depicted below:

Vectren is also involved in non-utility activities in two primary business areas: Infrastructure Services and energy services, provided through ESG. Infrastructure Services provides underground pipeline construction and repair services. ESG’s energy services include providing energy performance contracting and sustainable infrastructure, such as renewables, distributed generation and combined heat and power projects.

For ~~financial information about our segments,~~further discussion of the Merger, see Note 174 to ~~our~~the consolidated financial ~~statements, which note is incorporated herein by reference.~~statements.

REGULATION

WeThe Registrants are subject to regulation by various federal, state and local governmental agencies, including the regulations described below. The following discussion is based on regulation in the Registrants’ businesses and CenterPoint Energy’s investment in Enable as of December 31, 2018 and does not include Vectren-related regulation.

Federal Energy Regulatory Commission

The FERC has jurisdiction under the ~~Natural Gas Act~~NGA and the ~~Natural Gas Policy Act of 1978,~~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 ~~and criminal~~ penalties (up to approximately $1.27 million per day per violation, subject to periodic adjustment to account for inflation) for statutory violations and violations of the FERC’s rules or orders. ~~Our~~CenterPoint Energy’s and CERC’s Energy Services ~~business~~reportable segment markets natural gas in interstate commerce pursuant to blanket authority granted by the FERC.

~~CenterPoint~~ Houston Electric is not a “public utility” under the Federal Power Act 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 ~~CenterPoint~~ Houston Electric and other utilities within ERCOT. The FERC has designated the NERC as the ~~Electric Reliability Organization (ERO)~~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 ~~TRE. CenterPoint~~Texas RE. Houston Electric does not anticipate that the reliability standards proposed by the NERC and approved by the FERC will have a material adverse impact on its operations. To the extent that ~~CenterPoint~~ Houston Electric is required to make additional expenditures to comply with these standards, it is anticipated that ~~CenterPoint~~ Houston Electric will seek to recover those costs through the transmission charges that are imposed on all distribution service providers within ERCOT for electric transmission provided.

As a public utility holding company, under the Public Utility Holding Company Act of 2005, weCenterPoint Energy and ~~our~~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.

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

~~CenterPoint~~ Houston Electric conducts its operations pursuant to a certificate of convenience and necessity issued by the ~~Texas Utility Commission~~PUCT that covers its present service area and facilities. The ~~Texas Utility Commission~~PUCT and certain municipalities have the authority to set the rates and terms of service provided by ~~CenterPoint~~ Houston Electric under cost-of-service rate regulation. ~~CenterPoint~~ Houston Electric holds non-exclusive franchises from certain incorporated municipalities in its service territory. In exchange for payment of fees, these franchises give ~~CenterPoint~~ 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.

~~CenterPoint Houston’s~~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 ~~CenterPoint Houston’s~~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 ~~energy efficiency cost recovery~~EECR charge, ~~a surcharge related to the implementation of AMS~~ 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 ~~CenterPoint~~ Houston Electric the same rates and other charges for transmission services.

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

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

In almost all communities in which CERC’s NGD provides natural gas distribution services, itNGD operates under franchises, certificates or licenses obtained from state and local authorities. The original terms of the franchises, with various expiration dates, typically range from 10 to 30 years, although franchises in Arkansas are perpetual. NGD expects to be able to renew expiring franchises. In most cases, franchises to provide natural gas utility services are not exclusive.

Substantially all of NGD is subject to cost-of-service rate regulation by the relevant state public utility commissions and, in Texas, by the Railroad Commission ~~of Texas (Railroad Commission)~~ and those municipalities served by NGD that have retained original jurisdiction. In certain of its jurisdictions, NGD has ~~in effect~~ annual rate adjustment mechanisms that provide for changes in rates dependent upon certain changes in invested capital, earned returns on equity or actual margins realized.

For a discussion of certain of NGD’s ongoing regulatory proceedings, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Regulatory ~~Matters — CERC”~~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 ~~Pipeline Inspection, Protection, Enforcement and Safety~~2006 Act, ~~of 2006 (2006 Act),~~ which reauthorized the programs adopted under the ~~Pipeline Safety Improvement Act of~~ 2002 ~~(2002 Act).~~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 ~~Pipeline and Hazardous Materials Safety Administration (PHMSA) at the Department of Transportation (DOT)~~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. ~~Our~~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 ~~Pipeline Safety, Regulatory Certainty, and Job Creation Act of~~ 2011 ~~(2011 Act).~~Act. This act ~~increases~~increased the maximum civil penalties for pipeline safety administrative enforcement actions; ~~requires~~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; ~~requires~~required pipeline operators to verify their records on maximum allowable operating pressure; and ~~imposes~~imposed new emergency response and incident notification requirements. In 2016, the 2016 Act reauthorized PHMSA’s pipeline safety programs through 2019 and provided limited new authority, including the ability to issue emergency orders, to set inspection requirements for certain underwater pipelines and to promulgate minimum safety standards for natural gas storage facilities, as well as to provide increased transparency into the status of as-yet-incomplete PHMSA actions required by the 2011 Act.

WeCenterPoint Energy and CERC anticipate that compliance with PHMSA’s regulations, performance of the remediation activities by CenterPoint Energy’s and CERC’s natural gas distribution companies and intrastate pipelines and verification of records on maximum allowable operating pressure will continue to require increases in both capital expenditures and operating costs. The level of expenditures will depend upon several factors, including age, location and operating pressures of the facilities. In particular, the cost of compliance with the DOT’s integrity management rules

will depend on integrity testing and the repairs found to be necessary by such testing. Changes to the amount of pipe subject to integrity management, whether by expansion of the definition of the type of areas subject to integrity management procedures or of the applicability of such procedures outside of those defined areas, may also affect the costs ~~we incur.~~incurred. Implementation of the 2011 ~~Act~~and 2016 Acts by PHMSA may result in other regulations or the reinterpretation of existing regulations that could impact ~~our~~ compliance costs. In addition, weCenterPoint Energy and CERC may be subject to the DOT’s enforcement actions and penalties if wethey fail to comply with pipeline regulations. ~~Please also see the discussion under “— Midstream Investments — Safety and Health Regulation” below.~~

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.~~business.

Interstate Natural Gas Pipeline Regulation

Enable’s interstate pipeline ~~systems — Enable Gas Transmission, LLC (EGT), Enable-Mississippi River Transmission, LLC (MRT)~~systems—EGT, MRT and ~~SESH —~~ SESH—are subject to regulation by the FERC ~~under the Natural Gas Act of 1938 (NGA)~~ and are considered ~~natural~~“natural gas ~~companies. Natural gas companies may not charge rates that have been determined to be unjust or unreasonable by~~companies” under the ~~FERC. In addition, the FERC prohibits natural gas companies from unduly preferring or unreasonably discriminating against any person with respect to pipeline rates or terms and conditions of service.~~NGA. Under the NGA, the rates for service on Enable’s interstate facilities must be just and reasonable and not unduly discriminatory. ~~Generally,~~Rate and tariff changes for these facilities can only be implemented upon approval by the maximum filed recourse rates for interstate pipelines are based on the pipeline’s cost of service including recovery of and a return on the pipeline’s actual prudent investment cost. Key determinants in the ratemaking process are costs of providing service, allowed rate of return, volume throughput and contractual capacity commitment assumptions.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. ~~Tariff changes can only be implemented upon approval by the FERC.~~

Market Behavior Rules; Posting and Reporting Requirements

~~On August 8, 2005, Congress enacted the Energy Policy Act of 2005 (EPAct of 2005). Among other matters, the~~The EPAct of 2005 amended the NGA to add an anti-manipulation provision that makes it unlawful for any entity to engage in prohibited behavior as prescribed in ~~contravention of~~FERC rules, ~~and regulation to be prescribed by the~~which were subsequently issued in FERC ~~and, furthermore, provides the FERC with additional civil penalty authority. On January 19, 2006, the FERC issued~~ Order No. 670, a rule implementing the anti-manipulation provisions of the EPAct of 2005. The rules make it unlawful for any entity, directly or indirectly in connection with the purchase or sale of natural gas subject to the jurisdiction of the FERC or the purchase or sale of transportation services subject to the jurisdiction of the FERC, to (1) use or employ any device, scheme or artifice to defraud; (2) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements not misleading; or (3) to engage in any act or practice that operates as a fraud or deceit upon any person.670. The EPAct of 2005 also amends the NGA and the ~~Natural Gas Policy Act of 1978 (NGPA)~~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 $1approximately $1.27 million per day per violation, subject to periodic adjustment to account for ~~violations occurring after August 8, 2005.~~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 ~~Commodity Futures Trading Commission (CFTC)~~CFTC is directed under the ~~Commodities Exchange Act (CEA)~~CEA to prevent price manipulations

for the commodity and futures markets, including the energy futures markets. Pursuant to the Dodd-Frank Act and other authority, the CFTC has adopted anti-market manipulation regulations that prohibit fraud and price manipulation in the commodity and futures markets. The CFTC also has statutory authority to seek civil penalties of up to the greater of $1$1.2 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

Enable’s transmission lines are subject to state regulation of rates and terms of service. In Oklahoma, its intrastate pipeline system is subject to regulation by the Oklahoma Corporation Commission. Oklahoma has a non-discriminatory access requirement, which is subject to a complaint-based review. In Illinois, Enable’s intrastate pipeline system is subject to regulation by the Illinois Commerce Commission.

Intrastate natural gas transportation is largely regulated by the state in which the transportation takes place. AnHowever, 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 ~~FERC regulation and~~ Section 311 of the NGPA and Part 284 of the FERC’s regulations. The NGPA regulates, among other things, the provision of transportation and storage services by an intrastate natural gas pipeline on behalf of an interstate natural gas pipeline or a local distribution company served by an interstate natural gas pipeline. Under Section 311, rates charged for transportation must be fair and equitable, and amounts collected in excess of fair and equitable rates are subject to refund with interest. The rates under Section 311 are maximum rates and Enable may negotiate contractual rates at

~~or below such maximum rates.~~ 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. ~~Should the FERC determine not to authorize rates equal to or greater than Enable’s currently approved Section 311 rates, its business may be adversely affected.~~

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

Natural Gas Gathering ~~Pipeline~~and Processing Regulation

Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of the FERC. Although the FERC has not made formal determinations with respect to all of the facilities Enable considers to be gathering facilities, itEnable believes that its natural gas pipelines meet the traditional tests that the FERC has used to determine that a pipeline is a gathering pipeline and is therefore not subject to FERC jurisdiction. The distinction, ~~between FERC-regulated transmission services and federally unregulated gathering services,~~ however, has been the subject of substantial litigation, and the FERC determines whether facilities are gathering facilities on a case-by-case basis, so the classification and regulation of Enable’s gathering facilities is subject to change based on future determinations by the FERC, the courts or Congress. If the FERC were to consider the status of an individual facility and determine that the facility and/or services provided by it are not exempt from FERC regulation under the NGA and that the facility provides interstate service, the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by the FERC under the NGA or the NGPA. Such regulation could decrease revenue, increase operating costs, and, depending upon the facility in question, could adversely affect Enable’s results of operations and cash flows. In addition, if any of Enable’s facilities were found to have provided services or otherwise operated in violation of the NGA or the NGPA, this could result in the imposition of civil penalties as well as a requirement to disgorge charges collected for such service in excess of the rate established by the FERC.determinations.

States may regulate gathering pipelines. State regulation ~~of gathering facilities~~ generally includes various safety, environmental and, in some circumstances, anti-discrimination requirements, ~~prohibiting undue discrimination,~~ and in some instances complaint-based rate regulation. Enable’s gathering operations may be subject to ratable take and common purchaser statutes in the states in which they operate. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply and have the effect of restricting Enable’s right as an owner of gathering facilities to decide with whom it contracts to purchase or transport natural gas.

Enable’s gathering operations could be adversely affected should they be subject in the future to the application of state or federal regulation of rates and services. Enable’s gathering operations could also be subject to additional safety and operational regulations relating to the design, construction, testing, operation, replacement and maintenance of gathering facilities. ~~Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We~~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 provides interstate transportation on its~~Enable’s crude oil gathering ~~system~~systems in ~~North Dakota~~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 ~~provide~~transport crude oil in interstate ~~transportation service~~commerce may be regulated as a common ~~carrier~~carriers by the FERC under the ~~Interstate Commerce Act (ICA),~~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 ~~are to be~~ non-discriminatory or not ~~confer~~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. ~~Under~~

Intrastate Crude Oil and Condensate Gathering Regulation

Enable’s crude oil and condensate gathering system in the ~~ICA,~~Anadarko Basin is located in Oklahoma and is subject to limited regulation by the ~~FERC~~OCC. Crude oil and condensate gathering systems are common carriers under Oklahoma law and are prohibited from unjust or ~~interested persons may challenge existing~~unlawful discrimination in favor of one customer over another. Additional rules and legislation pertaining to these matters are considered or ~~changed rates~~adopted from time to time. Enable’s crude oil and condensate gathering operations could be adversely affected should they be subject in the future to the application of state or ~~services. The FERC is authorized to investigate such charges and may suspend the effectiveness~~federal regulation of a new rate for up to seven months. A successful rate challenge could result in a common carrier paying refunds together with interest for the period that the rate was in effect. The FERC may also order a pipeline to change its rates and ~~may require a common carrier to pay shippers reparations for damages sustained for a period up to two years prior to the filing of a complaint.~~ services.

For some time now, the FERC has been issuing regulatory assurances that necessarily balance the anti-discrimination and undue preference requirements of common carriage with the expectations of investors in new and expanding petroleum pipelines. There is an inherent tension between the requirements imposed upon a common carrier and the need for owners of petroleum

pipelines to be able to enter into long-term, firm contracts with shippers willing to make the commitments which underpin such large capital investments. The FERC’s solution has been to allow carriers to hold an “open season” prior to the in-service date of pipeline, during which time interested shippers can make commitments to the proposed pipeline project. Throughput commitments from interested shippers during an open season can be for firm service or for non-firm service. Typically, such an open season is for a 30-day period, must be publicly announced, and culminates in interested parties entering into transportation agreements with the carrier. Under FERC precedent, a carrier typically may reserve up to 90% of available capacity for the provision of firm service to shippers making a commitment. At least 10% of capacity ordinarily is reserved for “walk-up” shippers.

~~Midstream Investments –~~ 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 ~~pipeline safety~~ regulations, but natural gas gathering pipelines are subject ~~to the pipeline safety regulations~~ 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 ~~Natural Gas Pipeline Safety Act of 1968 (NGPSA),~~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. PHMSA has developed regulations that require natural gas pipeline operators to implement integrity management programs, including more frequent inspections and other measures to ensure pipeline safety in high consequence areas. Although many of Enable’s pipeline facilities fall within a class that is currently not subject to these integrity management requirements, Enable may incur significant costs and liabilities associated with repair, remediation, preventive or mitigating measures associated with its non-exempt pipelines. Additionally, shouldShould Enable fail to comply with DOT or comparable state regulations, it could be subject to penalties and fines. If future DOT pipeline ~~integrity management~~ regulations were to require that Enable expand its integrity ~~managements~~management program to currently unregulated pipelines, ~~including gathering lines, its~~ costs associated with compliance may have a material effect on its operations.

ENVIRONMENTAL MATTERS

~~Our~~The following discussion is based on environmental matters in the Registrants’ businesses as of December 31, 2018 and does not include Vectren-related environmental matters. 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, and the facilities that support these systems, wethe Registrants must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact ~~our~~the Registrants’ business activities in many ways, ~~such as:~~including, but not limited to:

restricting the way wethe Registrants can handle or dispose of wastes;

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

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

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

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

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

construct or acquire new facilities and equipment;

acquire permits for facility operations;

modify, upgrade or replace existing and proposed equipment; and

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

Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial actions and 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~~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 ~~affect~~impact the environment. For example, the Environmental Protection Agency (EPA) has also established air emission control requirements for natural gas and NGL production, processing and transportation activities, which may affect Enable’s midstream operations. These include New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds, and the National Emission Standards for Hazardous Air Pollutants (NESHAPS) to address hazardous air pollutants frequently associated with natural gas production and processing activities. There can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation and monitoring, and actual future expenditures may be different from the amounts we currently ~~anticipate. We~~anticipated. The

Registrants try to anticipate future regulatory requirements that might be imposed and plan accordingly to maintain compliance with changing environmental laws and ~~regulations and to ensure the costs of such compliance are reasonable.~~regulations.

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

Global Climate Change

There is increasing attention being paid in the United States and worldwide to the issue of climate change. As a result, from time to time, regulatory agencies have considered the modification of existing laws or regulations or the adoption of new laws or regulations addressing the emissions of ~~greenhouse gases (GHG)~~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 ~~its~~their operations or would have the effect of reducing the consumption of natural gas. ~~Our electric transmission and distribution business,~~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 ~~Houston’s~~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 ~~its~~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 ~~our~~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 ~~its~~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 ~~our~~the Registrants’ businesses.

To the extent climate changes may occur ~~our businesses may be adversely impacted, though we believe any~~and such ~~impacts are likely to occur very gradually and hence would be difficult to quantify. To the extent global~~ climate ~~change results~~changes result in warmer temperatures in ~~our~~the Registrants’ or Enable’s service territories, financial results from ~~our natural gas distribution business~~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.~~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 ~~our~~CenterPoint Energy’s and Houston Electric’s electric service territory may increase ~~our~~ revenues from transmission and distribution through increased demand for electricity for cooling. Another possible ~~effect~~result of climate change is more frequent and more severe weather events, such as hurricanes or tornadoes. Since many of ~~our~~the Registrants’ 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 wethe Registrants cannot deliver electricity or natural gas to customers, or ~~our~~ customers cannot receive ~~our~~ services, ~~our~~the Registrants’ financial results can be impacted by lost revenues, and wethey generally must seek approval from regulators to recover restoration costs. To the extent wethe Registrants are unable to recover those costs, or if higher rates resulting from ~~our~~ recovery of such costs result in reduced demand for ~~our~~ services, ~~our~~the Registrants’ future financial results may be adversely impacted.

Air Emissions

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

The EPA has established new air emission control requirements for natural gas and ~~natural gas liquids~~NGLs production, processing and transportation activities. Under the NESHAPS, the EPA established ~~maximum achievable control technology for stationary internal combustion engines (sometimes referred to as~~ the RICE MACT ~~rule).~~rule. Compressors and back up electrical

generators used by CenterPoint Energy’s and CERC’s NGD, and back up electrical generators used by ~~our Natural Gas Distribution segment,~~CenterPoint Energy and ~~back up electrical generators used by our~~Houston Electric, ~~Transmission & Distribution segment,~~ are substantially compliant with these laws and regulations.

Water Discharges

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

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. As initially promulgated, these regulations would expand federal jurisdiction under the Clean Water Act and, therefore, have the potential to affect many aspects of the Registrants’ water-related regulatory compliance obligations. However, the new rules were challenged in court, and the U.S. Supreme Court has recently held that any challenge to the rules must be brought in the U.S. district courts rather than directly before the U.S. courts of appeals. As a result, the new definition of the “waters of the United States” is likely to be disputed in litigation for years to come. Additionally, the Trump administration has 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. Thus, the fate and content of the regulations defining “waters of the United States” is currently uncertain, and it is not clear when, and even if, they will be enacted. 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.

Hazardous Waste

~~Our~~The Registrants’ operations generate wastes, including some hazardous wastes, that are subject to the federal ~~Resource Conservation and Recovery Act (RCRA),~~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.

Liability for Remediation

~~The Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (CERCLA),~~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~~“hazardous substances” into the environment. ~~Such classes~~Classes of ~~persons~~PRPs include the current and past owners or operators of sites where a hazardous substance was released and companies that disposed or arranged for the disposal of hazardous substances at offsite locations such as landfills. Although petroleum, as well as natural gas, is expressly excluded from CERCLA’s definition of a “hazardous substance,” in the course of ~~our~~the Registrants’ ordinary operations wethey do, from time to time, generate wastes that may fall within the definition of a “hazardous substance.” CERCLA authorizes the EPA and, in some cases, third parties to take action in response to threats to the public health or the environment and to ~~seek to~~ recover the costs they incur from the responsible classes of ~~persons the costs they incur.~~persons. Under CERCLA, wethe Registrants could potentially be subject to joint and several liability for the costs of cleaning up and restoring sites where hazardous substances have been released, for damages to natural resources, and for associated response and assessment costs, including for the costs of certain health studies.

Liability for Preexisting Conditions

~~Manufactured Gas Plant Sites.~~ CERC and its predecessors operated manufactured gas plants (MGPs) in the past. With respect to certain Minnesota MGP sites, CERC has completed state-ordered remediation and continues state-ordered monitoring and water treatment. As of December 31, 2015, CERC had a recorded liability of $7 million for continued monitoring and any future remediation required by regulators in Minnesota. The estimated range of possible remediation costs for the sites for which CERC

believes it may have responsibility was $5 million to $29 million based on remediation continuing for 30 to 50 years. 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 potentially responsible parties (PRPs), if any, and the remediation methods used.

~~In addition~~For information about preexisting environmental matters, please see Note 16(d) to the Minnesota sites, the EPA and other regulators have investigated MGP sites that were owned or operated by CERC or may have been owned by one of its former affiliates. We do not expect the ultimate outcome of these matters to have a material adverse effect on theconsolidated financial ~~condition, results of operations or cash flows of either us or CERC.~~

~~Asbestos.~~ Some facilities owned by us contain or have contained asbestos insulation and other asbestos-containing materials. We or our subsidiaries have been named, along with numerous others, as defendants in lawsuits filed by a number of individuals who claim injury due to exposure to asbestos. Some of the claimants have worked at locations owned by us, but most existing claims relate to facilities previously owned by our subsidiaries. In 2004, we sold our generating business, to which most of these claims relate, to a company which is now an affiliate of NRG. Under the terms of the arrangements regarding separation of the generating business from us and our sale of that business, ultimate financial responsibility for uninsured losses from claims relating to the generating business has been assumed by the NRG affiliate, but we have agreed to continue to defend such claims to the extent they are covered by insurance maintained by us, subject to reimbursement of the costs of such defense by the NRG affiliate. We anticipate that additional claims like those received may be asserted in the future. Although their ultimate outcome cannot be predicted at this time, we intend to continue vigorously contesting claims that we do not consider to have merit and do not expect, based on our experience to date, these matters, either individually or in the aggregate, to have a material adverse effect on our financial condition, results of operations or cash flows.

~~Other Environmental.~~ From time to time we identify the presence of environmental contaminants on property where we conduct or have conducted operations. Other such sites involving contaminants may be identified in the future. We have remediated and expect to continue to remediate identified sites consistent with our legal obligations. From time to time we have received notices from regulatory authorities or others regarding our status as a PRP in connection with sites found to require remediation due to the presence of environmental contaminants. In addition, we have been named from time to time as a defendant in litigation related to such sites. Although the ultimate outcome of such matters cannot be predicted at this time, we do not expect, based on our experience to date, these matters, either individually or in the aggregate, to have a material adverse effect on our financial condition, results of operations or cash flows.statements.

EMPLOYEES

~~As of December 31, 2015, we had 7,505 full-time employees.~~ The following table sets forth the number of ~~our~~ employees by ~~business~~Registrant and reportable segment as of December 31, ~~2015:~~2018:


Business Segment	Number	Number Represented by Collective Bargaining Groups
			Number of Employees			Number of Employees Represented by Collective Bargaining Groups
Reportable Segment			CenterPoint Energy	Houston Electric	CERC	CenterPoint Energy	Houston Electric	CERC
Electric Transmission & Distribution	2,665	1,349	2,800	2,800	—	1,431	1,431	—
Natural Gas Distribution	3,286	1,173	3,298	—	3,298	1,200	—	1,200
Energy Services	135	—	302	—	302	—	—	—
Other Operations	1,419	110	1,577	—	—	127	—	—
Total	7,505	2,632	7,977	2,800	3,600	2,758	1,431	1,200

AsFor information about the status of December 31, 2015, approximately 35% of our employees were covered by collective bargaining agreements. The collective bargaining agreement with the International Brotherhood of Electrical Workers Local 66 and the two collective bargaining agreements, ~~with Professional Employees International Union Local 12, which collectively cover approximately 21% of our employees, are scheduled~~see Note 8(j) to ~~expire in March and May of 2016. We believe we have good relationships with these bargaining units and expect to negotiate new agreements in 2016.~~the consolidated financial statements.

EXECUTIVE OFFICERS

(as of February 12, ~~2016)~~2019)



Name	Age	Title
Milton Carroll	6568	Executive Chairman
Scott M. Prochazka	4952	President and Chief Executive Officer and Director
William D. Rogers	5558	Executive Vice President and Chief Financial Officer
Tracy B. Bridge	5760	Executive Vice President and President, Electric Division
~~Joseph B. McGoldrick~~Scott E. Doyle	6247	~~Executive~~Senior Vice President, ~~and~~Natural Gas Distribution
Joseph J. Vortherms	58	Senior Vice President, ~~Gas Division~~Energy Services
Dana C. O’Brien	4851	Senior Vice President and General Counsel ~~and Corporate Secretary~~
Sue B. Ortenstone	5862	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 and Western Gas Holdings, LLC, the general partner of Western Gas Partners, LP, since ~~2008 and LyondellBasell Industries N.V. since July 2010.~~2008. He has served as a director of ~~Healthcare~~Health Care Service Corporation since 1998 and as its chairman since 2002. He previously served as a director of LyondellBasell Industries N.V. from July 2010 to July 2016 as well as LRE GP, LLC, the general partner of LRR Energy, L.P., from November 2011 to January 2014.

Scott M. Prochazka has served as a Director and President and Chief Executive Officer ~~(CEO)~~ of CenterPoint Energy since January 1, 2014. He previously served as Executive Vice President and Chief Operating Officer from July 2012 to December 2013; as Senior Vice President and Division President, Electric Operations from May 2011 through July 2012; as Division Senior Vice President, Electric Operations of ~~CenterPoint~~ Houston Electric from February 2009 to May 2011; as Division Senior Vice President, Regional Operations of CERC from February 2008 to February 2009; and as Division Vice President, Customer Service Operations, from October 2006 to February 2008. He currently serves on the ~~Boards~~Board of Directors of Enable GP, LLC, the general partner of Enable Midstream Partners, LP, and as the Chairman of the Board of Directors for each of Gridwise Alliance and Central Houston, Inc. Mr. Prochazka is also a board member of Edison Electric Institute, Electric Power Research Institute, American Gas Association, Greater Houston Partnership, ~~and~~United Way of Houston, Junior Achievement of South ~~Texas.~~Texas and the Kinder Institute Advisory Board.

William D. Rogers has served as Executive Vice President and Chief Financial Officer of CenterPoint Energy since March 2015. He previously served as Executive Vice President, Finance and Accounting from February 2015 to March 2015. Prior to joining CenterPoint Energy, Mr. Rogers was Vice President and Treasurer of American Water Works Company, Inc., the largest publicly traded U.S. water and wastewater utility company, from October 2010 to January 2015. Mr. Rogers was also the Chief Financial Officer of NV Energy, Inc., an investor-owned utility headquartered in Las Vegas serving approximately 1.5 million electric and gas customers in Nevada and with annual revenues of approximately ~~$3.0~~$3 billion, from February 2007 to February 2010. He has previously served as NV Energy’s vice president of finance, risk and tax, as well as corporate treasurer. Before joining NV Energy in June 2005, Mr. Rogers was a managing director in capital markets at Merrill Lynch and prior to that worked in a similar

role at JPMorgan Chase in New York. He currently serves on the ~~Board~~Boards of Directors of Enable GP, LLC, the general partner of Enable Midstream Partners, ~~LP.~~LP, the West Point Association of Graduates and Sheltering Arms of New York.

Tracy B. Bridge has served as Executive Vice President and President, Electric Division since February 2014. He previously served as Senior Vice President and Division President, Electric Operations from September 2012 to February 2014; as Senior Vice President and Division President, Gas Distribution Operations from May 2011 to September 2012; as Division Senior Vice President - Support Operations from February 2008 to May 2011; and as Division Vice President Regional Operations of CERC from January 2007 to February 2008. Mr. Bridge has more than 35 years of utility experience. He currently serves onas the Chair of the Board of Directors of Rebuilding Together Houston.

~~Joseph B. McGoldrick~~ Scott E. Doylehas served as ~~Executive~~Senior Vice President, ~~and President,~~Natural Gas ~~Division~~Distribution since ~~February 2014. He~~March 2017. With more than 20 years of utility experience, he previously served as Senior Vice President, Regulatory and Public Affairs from February 2014 to March 2017; as Division Vice President, ~~Gas Operations~~Rates and Regulatory from ~~September~~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 and the Southern Gas Association. He previously served on the boards of the Texas Gas Association and the Association of Electric Companies of Texas.

Joseph J. Vortherms has served as Senior Vice President, ~~and Division~~Energy Services since March 2017. He previously served as Vice President, Energy Services from ~~May 2011~~November 2015 to ~~September~~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 ~~Division President, Gas Operations~~Director, Home Service Plus from ~~February~~January 2007 to ~~May 2011.~~April 2012. Mr. ~~McGoldrick is a member of~~Vortherms currently serves on the Southern Gas Association Executive Council as well as the American Gas ~~Association’s Leadership~~Association Scenario Planning Council. He previously served on the boards of the Minnesota Region American Red Cross and the Minnesota Business Partnership.

Dana C. O’Brien has served as Senior Vice President and General Counsel ~~and Corporate Secretary~~ of CenterPoint Energy since May 2014. Additionally, she served as Corporate Secretary of the Company until October 2017. Before joining CenterPoint Energy, Ms. O’Brien was Chief Legal Officer and Chief Compliance Officer and a member of the executive board at CEVA Logistics, a Dutch-based logistics company, from August 2007 to April 2014. She previously served as the general counsel at EGL, Inc. from October 2005 to July 2007 and Quanta Services, Inc. from January 2001 to October 2005. Ms. O’Brien ~~serves~~was appointed as a director ~~for the Association~~ of ~~Women Attorneys Foundation,~~Sterling Construction Company, Inc., a publicly traded company, effective January 1, 2019. She previously served as a member of the ~~Board~~Boards of Directors of Ronald McDonald House Houston, ~~and as a member of the Board of Directors of~~ Child Advocates, Inc. and the Association of Women Attorneys Foundation.

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 ~~Advisory Board for Civil and Environmental Engineering, as well as the~~ Industrial Advisory Board in the College of Engineering at the University of Wisconsin. ~~She~~Ms. Ortenstone also serves on the Board of Trustees for Northwest Assistance Ministries of Houston.


Item 1A.	Risk Factors

~~We are~~CenterPoint Energy is a holding company that conducts all of ~~our~~its business operations through subsidiaries, primarily Houston Electric, CERC and, as of February 1, 2019, Vectren through its operating subsidiaries. CenterPoint ~~Houston and CERC. We~~Energy also ~~own~~owns interests in ~~Enable, a publicly traded midstream master limited partnership jointly controlled by CERC Corp. and OGE.~~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 ~~our~~its subsidiaries, including Vectren, and ~~our~~its interests in ~~Enable:~~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. Carefully consider each of the risks described below relating to Houston Electric and CERC, which, along with CenterPoint Energy (including Vectren for purposes of this Item 1A only), 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, which, as of February 1, 2019, includes Vectren and its subsidiaries.

Risk Factors Associated with Our Consolidated Financial Condition

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

~~We derive~~CenterPoint Energy derives all of ~~our~~its operating income from, and ~~hold~~holds all of ~~our~~its assets through, ~~our~~its subsidiaries, including ~~our~~its interests in Enable. As a result, ~~we depend~~CenterPoint Energy depends on distributions from ~~our~~its subsidiaries ~~including~~and Enable ~~in order~~ to meet ~~our~~its payment obligations and to pay dividends on ~~our~~its common and preferred stock. In general, ~~our~~CenterPoint Energy’s subsidiaries are separate and distinct legal entities and have no obligation to provide usit with funds for ~~our~~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 ~~our~~CenterPoint Energy’s subsidiaries’ and Enable’s ability to make payments or other distributions to ~~us,~~CenterPoint Energy, and ~~our~~its subsidiaries or Enable could agree to contractual restrictions on their ability to make distributions. Additionally, CenterPoint Energy’s results of operations, future growth and earnings and dividend goals will 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. CenterPoint Energy and CERC also offer home repair protection plans to natural gas customers in Texas (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 ~~we receive~~CenterPoint Energy receives with respect to ~~our~~its interests in Enable, please read “— Additional Risk Factors Affecting ~~Our~~CenterPoint Energy’s Interests in Enable Midstream Partners, LP — ~~Our~~CenterPoint Energy’s cash flows will be adversely impacted if ~~we receive~~it receives less cash distributions from Enable than weit currently ~~expect.~~expects.”

~~Our~~CenterPoint Energy’s right to receive any assets of any subsidiary, and therefore the right of ~~our~~its creditors to participate in those assets, will be ~~effectively~~structurally subordinated to the claims of that subsidiary’s creditors, including trade creditors. In addition, even if weCenterPoint Energy were a creditor of any subsidiary, ~~our~~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 ~~us.~~CenterPoint Energy.

If we are unable to arrange future financings on acceptable terms, our ability to finance our capital expenditures or refinance ~~existing~~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 (CenterPoint Energy may also depend on the net proceeds from a sale of a portion of Enable common units it owns) 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, ~~2015, we~~2018, CenterPoint Energy had ~~$8.8~~$9.2 billion of outstanding indebtedness on a consolidated basis, which includes ~~$2.7~~$1.4 billion of non-recourse ~~transition and system restoration bonds.~~Securitization Bonds. For information on maturities through 2023, see Note 14 to the consolidated financial statements. As of December 31, ~~2015, approximately $1.5~~2018, Vectren and its subsidiaries had outstanding $167 million of short-term debt and $2.2 billion ~~principal amount~~ of ~~this~~long-term debt, ~~is required to be paid through 2018. This amount excludes principal repayments of approximately $1.2 billion on transition and system restoration bonds, for which dedicated revenue streams exist.~~including current maturities. 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;

~~market perceptions of~~ our ability to access capital markets on reasonable terms;

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

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

provisions of relevant tax and securities laws.

As of December 31, ~~2015, CenterPoint~~2018, Houston Electric had approximately ~~$2.1~~$3.3 billion aggregate principal amount of general mortgage bonds outstanding under the General Mortgage, including ~~(a)~~ approximately $56 million held in trust to secure pollution control bonds that are not reflected on our financial statements because CenterPoint Houston is both the obligor on the bonds and the current owner of the bonds, and (b) approximately $118$68 million held in trust to secure pollution control bonds for which ~~we are~~CenterPoint Energy is obligated. Additionally, as of December 31, ~~2015, CenterPoint~~2018, Houston Electric had approximately $102 million aggregate principal amount of first mortgage bonds outstanding under the Mortgage. ~~CenterPoint~~ 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. ~~Approximately $4.2~~As of December 31, 2018, approximately $4.3 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, ~~2015.~~2018. However, ~~CenterPoint~~ Houston Electric has contractually agreed that it will not issue additional first mortgage bonds, subject to certain exceptions. In January 2019, Houston Electric issued $700 million aggregate principal amount of general mortgage bonds. As of December 31, 2018, Indiana Electric had approximately $293 million aggregate principal amount of first mortgage bonds outstanding. Indiana Electric may issue additional bonds under its Mortgage Indenture up to 60% of currently unfunded property additions. As of December 31, 2018, approximately $1.0 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.

~~Our~~The Registrants’ current credit ratings 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. WeOn January 28, 2019, in anticipation of the closing of the Merger, Moody’s downgraded the long-term credit ratings of CenterPoint Energy, including its issuer rating to Baa2 from Baa1, senior unsecured debt rating to Baa2 from Baa1, subordinated debt rating to Baa3 from Baa2 and preferred stock rating to Ba1 from Baa3 while affirming its Prime‐2 short-term rating for commercial paper and A1 senior secured revenue bonds. Moody’s also changed the rating outlook for CenterPoint Energy to stable from negative. On February 1, 2019, as a result of the closing of the Merger, S&P lowered its issuer credit rating on CenterPoint Energy to BBB+ from A-, and lowered the credit ratings for CenterPoint Energy’s senior unsecured and subordinated notes to BBB from BBB+ and the Series A Preferred Stock to BBB- from BBB. S&P also removed the CenterPoint Energy ratings from CreditWatch, where S&P had previously placed them with negative implications as a result of the announcement of the Merger in the second quarter of 2018 and changed its outlook to stable. S&P also lowered its issuer credit ratings on Houston Electric and CERC to BBB+ from A-. S&P affirmed the A credit rating on Houston Electric’s first mortgage bonds and general mortgage bonds and lowered the credit rating on CERC’s senior unsecured debt to BBB+ from A-. S&P also removed the Houston Electric and CERC ratings from CreditWatch, where S&P had previously placed them with negative implications as a result of the announcement of the Merger in the second quarter of 2018 and changed its outlook to stable. S&P also affirmed the A-2 short-term and commercial paper ratings for CenterPoint Energy and CERC. The Registrants note that these credit ratings are not recommendations to buy, sell or hold ~~our~~their securities. Each rating should be evaluated independently of any other rating. Any future reduction or withdrawal of one or more of ~~our~~the Registrants’ credit ratings could have a material adverse impact on ~~our~~their ability to access capital on acceptable terms.

An impairment of goodwill, long-lived assets, including intangible assets, equity method investments and ~~equity-method investments~~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 usCenterPoint 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.

For investments ~~we account~~CenterPoint Energy accounts for under the equity method, the impairment test considers whether the fair value of ~~the equity~~such investment as a whole, not the underlying net assets, has declined and whether that decline is other than temporary. For example, ~~based on the sustained low Enable~~if Enable’s common unit price and further declines in such price during the three months ended September 30, 2015 and December 31, 2015, respectively, as well as the market outlook for continued depressed crude oil and natural gas prices impacting the midstream oil and gas industry, we determined in connection with our preparation of financial statements for the three months ended September 30, 2015 and December 31, 2015, that an other than temporary decrease in the value of our investment in Enable had occurred. We wrote down the value of our investment in Enable to its estimated fair value which resulted in impairment charges of $250 million as of September 30, 2015 and $975 million as of December 31, 2015. Our total impairment loss included impairment charges totaling $1,846 million composed of the impairments of our investment in Enable of $1,225 million and our share, $621 million, of impairment charges Enable recorded for goodwill and long-lived assets.

~~If Enable’s~~ unit price, distributions or earnings ~~further~~were to decline, ~~for reasons including, but not limited to, continued declines in commodity prices and producer activity,~~ and that decline is deemed to be other than temporary, weCenterPoint Energy could determine that ~~we are~~it is unable to recover the carrying value of ~~our~~its equity investment in Enable. As of December 31, 2015, the carrying value of CenterPoint Energy’s investment in Enable is $11.09 per unit, which includes the common and subordinated units representing limited partner interests, general partner interest and incentive distribution rights we hold. As of December 31, 2015, Enable’s common unit price closed at $9.20. The lowest close price for Enable’s common units through February 12, 2016 was $5.80. Considerable judgment is used in determining if an impairment loss is other than temporary and the amount of any impairment. A sustained low Enable common unit price ~~or further declines in such price~~ could result in ~~our~~CenterPoint Energy recording ~~further~~ impairment charges in the future. ~~If we~~

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 ~~that~~if an impairment analysis should be performed on its investment.

Further, as a result of the Merger, CenterPoint Energy will have a significant amount of goodwill and other intangible assets on its consolidated financial statements that are subject to impairment based on future adverse changes to its business or prospects.

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 ~~indicated,~~less than the carrying value, we would be required to take ~~an immediate~~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.

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

WeCenterPoint Energy and its subsidiaries maintain a qualified defined benefit pension ~~plan~~plans covering ~~substantially all~~certain of its employees. ~~Our costs of providing this plan~~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, ~~our~~ contributions to the plan, and government regulations with respect to funding requirements and the calculation of plan liabilities. Funding requirements may increase ~~as a result~~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 ~~our~~CenterPoint Energy’s funding requirements, each of these factors could adversely affect our results of operations, liquidity and financial position.

Vectren also contributes to several multi-employer pension plans for Infrastructure Services. 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 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 ~~us, our subsidiaries~~the Registrants or Enable could result in financial losses that could negatively impact ~~our~~the Registrants’ results of operations and those of ~~our subsidiaries or~~ Enable.

~~We and our subsidiaries~~The Registrants use derivative instruments, such as swaps, options, futures and forwards, to manage ~~our~~ commodity, weather and financial market risks. Enable may also use such instruments from time to time to manage its commodity and financial market ~~risk. We, our subsidiaries~~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. InAdditionally, 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, 2018. 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 ($93 million in the aggregate, or $6.57 per ZENS, as of December 31, 2018) 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, 2018, deferred taxes of approximately $438 million would have been payable in 2018, based on 2018 tax rates in effect. In addition, if all the shares of ZENS-Related Securities had been sold on December 31, 2018 to fund the aggregate redemption amount, capital gains taxes of approximately $90 million would have been payable in 2018. Similarly, a significant amount of exchanges of ZENS by ZENS holders could adversely impact CenterPoint Energy’s cash flows. This could happen if CenterPoint Energy’s creditworthiness were to drop or the market for the ZENS were to become illiquid, or for some other reason. While funds for the payment of cash upon exchange of ZENS could be obtained from the sale of the shares of ZENS-Related Securities that CenterPoint Energy owns or from other sources, ZENS exchanges result in a cash outflow 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.

In August 2018, CenterPoint Energy issued 800,000 shares of Series A Preferred Stock. In October 2018, CenterPoint Energy issued 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 ~~Our~~ Electric Generation, Transmission &and Distribution ~~Business~~Businesses (CenterPoint Energy and Houston Electric)

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

~~CenterPoint Houston’s~~Houston Electric’s rates are regulated by certain municipalities and the ~~Texas Utility Commission~~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 ~~its~~their invested capital, their expenses and ~~its expenses~~other factors in a designated test year. ~~Thus,~~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 last general base rate change, unless the PUCT issues an order extending the deadline to file that general base rate proceeding. In connection with the PUCT’s review of the impacts of the TCJA, on February 13, 2018, Houston Electric and other likely parties to a future rate case announced a settlement that, among other things, requires Houston Electric to make a general rate case filing by April 30, 2019. There is no guarantee that current rates will continue or that ~~CenterPoint Houston is allowed to charge may not match its costs at any given time, which is referred to as “regulatory lag.” The regulatory process by which rates are determined may not always~~the general rate case will result in rates that ~~will produce full recovery of CenterPoint Houston’s~~fully recover Houston Electric’s costs ~~and~~or enable ~~CenterPoint Houston~~it to earn a reasonable return on its invested capital.

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, though several interim rate adjustment mechanisms have been implemented to reduce the effects of regulatory lag, these adjustment mechanisms are subject to the

applicable regulatory body’s approval and are subject to limitations that may reduce Houston Electric’s and Indiana Electric’s ability to adjust rates. For example, 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. 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 cost as they are incurred, with the remaining costs to be deferred as regulatory assets until the next base rate case, and 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 Reliability Cost and Revenue Adjustment and MISO Cost and Recovery Adjustment mechanisms, which are filed annually. With respect to the DSMA, electricity suppliers are required to submit energy efficiency plans to the IURC at least once every three years and may file under the DSMA mechanism annually to recover program and administrative costs, including lost revenues and financial incentives. 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 adversely affected.

Unlike Houston Electric, Indiana Electric must seek approval by the IURC for long-term financing authority. This authority allows Indiana Electric the flexibility to issue debt securities,among other financing arrangements. In the event that the IURC does 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 adversely affected.

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

~~CenterPoint~~ Houston Electric transmits and distributes to customers of REPs electric power that the REPs obtain from power generation facilities owned by third parties. ~~CenterPoint~~ Houston Electric does not own or operate any power generation facilities. If power generation is disrupted or if power generation capacity is inadequate, ~~CenterPoint Houston’s~~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.

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

A significant portion of ~~CenterPoint Houston’s~~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. Thus, ~~CenterPoint Houston’s~~Houston Electric’s and Indiana Electric’s revenues and results of operations are subject to seasonality, weather conditions and other changes in electricity ~~usage, with~~usage. Houston Electric’s revenues are generally ~~being~~ higher during the warmer months. Unusually mild weather in the warmer months could diminish ~~our~~Houston Electric’s results of operations and harm ~~our~~its financial condition. Conversely, extreme warm weather conditions could increase ~~our~~Houston Electric’s results of operations in a manner that would not likely be annually recurring.

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

CenterPoint Houston has deployed an AMS throughout its service territory. The deployment consisted, among other elements, of replacing existing meters with new electronic meters that record metering data at 15-minute intervalsIndiana Electric’s sales are for space heating and wirelessly communicate that information to CenterPoint Houston over a bi-directional communications system installed for that purpose. The AMS integrates equipment and computer software from various vendors in order to eliminate the need for physical meter readings to be taken at consumers’ premises, such as monthly readings for billing purposes and special readings associated with a customer’s change in REPs or the connection or disconnection of electric service. Unanticipated difficulties could be encountered during the operation of the AMS, including failures or inadequacy of equipment or software, difficulties in integrating the various components

of the AMS, changes in technology, cyber-security issues and factors outside the control of CenterPoint Houston, which could result in delayed or inaccurate metering data that might lead to delays or inaccuracies in the calculation and imposition of delivery or other charges, which could have a material adverse effect on CenterPoint Houston’scooling. Consequently, Indiana Electric’s results of operations ~~financial condition and cash flows.~~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.

~~CenterPoint~~

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

~~The~~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 ~~CenterPoint~~ Houston Electric and other utilities within ~~ERCOT.~~ERCOT and Indiana Electric and other utilities within MISO, respectively. The FERC has designated the NERC as the ERO to promulgate standards, under FERC oversight, for all owners, operators and users of the bulk power system. The FERC has approved the delegation by the NERC of authority for reliability in ERCOT to the ~~TRE,~~Texas RE, a ~~functionally independent division~~Texas non-profit corporation and for reliability in the portion of ~~ERCOT.~~MISO that includes Indiana Electric to ReliabilityFirst Corporation, a Delaware non-profit corporation. Compliance with ~~the~~ mandatory reliability standards may subject ~~CenterPoint~~ Houston Electric and Indiana Electric to higher operating costs and may result in increased capital expenditures. In addition, if ~~CenterPoint~~ Houston Electric or Indiana Electric were to be found to be in noncompliance with applicable mandatory reliability standards, itthey could be subject to sanctions, including substantial monetary penalties.

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

~~CenterPoint Houston’s~~Houston Electric’s receivables from the distribution of electricity are collected from REPs that supply the electricity ~~CenterPoint~~ Houston Electric distributes to their customers. As of December 31, ~~2015, CenterPoint~~2018, Houston Electric did business with approximately 6965 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 ~~CenterPoint Houston’s~~Houston Electric’s services or could cause them to delay such payments. ~~CenterPoint~~ 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 ~~Texas Utility Commission~~PUCT regulations significantly limit the extent to which ~~CenterPoint~~ 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 ~~CenterPoint~~ 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. The Texas Utility Commission revised its regulations in 2009 to (i) increase the financial qualifications required of REPs that began selling power after January 1, 2009, and (ii) authorize utilities to defer bad debts resulting from defaults by REPs for recovery in a future rate case. A significant portion of ~~CenterPoint Houston’s~~Houston Electric’s billed receivables from REPs are from affiliates of NRG and Vistra Energy ~~Future Holdings~~Corp., formerly known as TCEH Corp. ~~(Energy Future Holdings). CenterPoint Houston’s~~Houston Electric’s aggregate billed receivables balance from REPs as of December 31, ~~2015~~2018 was ~~$195~~$207 million. Approximately 34% and ~~11%~~12% of this amount was owed by affiliates of NRG and Vistra Energy ~~Future Holdings,~~Corp., respectively. In April 2014, Energy Future Holdings publicly disclosed that it and the substantial majority of its direct and indirect subsidiaries, excluding Oncor Electric Delivery Company LLC and its subsidiaries, filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the District of Delaware. Any delay or default in payment by REPs could adversely affect ~~CenterPoint Houston’s~~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 ~~CenterPoint~~ Houston Electric had received from such REP.

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

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

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

As required by Indiana regulation, Indiana Electric filed its 2016 IRP with the IURC in December 2016. Indiana requires each electric utility to perform and submit an IRP 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. 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, which was issued in November 2017. Indiana Electric has taken the comments provided in the report into consideration in its generation resource plans.

Consistent with the recommendations presented in Indiana Electric’s IRP and as a direct result of significant environmental investments required to comply with current regulations, Indiana Electric plans to retire a significant portion of its current generating fleet by the end of 2023. Indiana Electric’s electric generation transition plan will require recovery of new capital investments, as well as costs of retiring the current generation fleet, including decommissioning costs, costs of removal and any remaining unrecovered costs of retired assets. Currently, Indiana Electric relies on coal for substantially all of its generation capacity. In February 2018, Indiana Electric filed a petition seeking authorization from the IURC to construct a new 800-900 MW natural gas combined cycle generating facility to replace this capacity at an approximate cost of $900 million, which includes the cost of a new natural gas pipeline to serve the plant. Indiana Electric is requesting a certificate of public convenience and necessity authorizing construction timelines and costs of new generation resources, as well as necessary unit retrofits, to implement the generation transition plan. Also, Indiana Electric is seeking approval to defer some capital costs associated with the generation plan until its next base rate proceeding and may use rate recovery mechanisms to recover other portions of the cost. Indiana Electric expects an order from the IURC in the certificate of public convenience and necessity proceeding in the first half of 2019. Given the significance of the plan, there is inherent risk associated with the construction of new generation, 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.

Additionally, Indiana Electric’s generating facilities are subject to operational risks that could result in unscheduled plant outages, unanticipated operation and maintenance expenses and increased purchase power costs. These operational risks can arise from circumstances such as facility shutdowns 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. Further, Indiana Electric’s 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.

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

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

~~CERC’s~~NGD’s rates ~~for NGD~~ are regulated by certain municipalities (in Texas only) and state commissions based on an analysis of ~~its~~NGD’s invested capital, expenses and ~~its expenses~~other factors in a test ~~year.~~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. Thus, the rates that ~~CERC~~NGD is allowed to charge may not match its costs at any given time, ~~which~~resulting in what is referred to as “regulatory lag.”

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

Arkansas allows public utilities to elect to have their rates regulated pursuant to a FRP, providing for a utility’s base rates to be adjusted once a year. In each of Louisiana, Mississippi and Oklahoma, NGD makes annual filings utilizing various formula rate mechanisms that adjust rates based on a comparison of authorized return to actual return to achieve the allowed return rates in those jurisdictions. Additionally, in Minnesota, the MPUC implemented a full revenue decoupling 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 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. NGD must file a general rate case no later than five years after the initial GRIP implementation date.

NGD can make no assurance that filings for such mechanisms will result in favorable adjustments to rates. Notwithstanding the application of the rate mechanisms discussed above, the regulatory process inby 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 ~~CERC’s~~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 ~~enable CERC to earn a reasonable return on~~timely recovery of appropriate costs, its ~~invested capital.~~results of operations, financial condition and cash flows could be adversely affected.

~~CERC’s~~Unlike CERC, Indiana Gas, SIGECO’s natural gas distribution business and ~~energy services businesses,~~VEDO must seek approval by the IURC and PUCO, as applicable, for long-term financing authority. This authority allows these utilities the flexibility to issue their debt securities, among other 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, including transportation and storage, whether through the use of AMAs or other arrangements, are subject to fluctuations in notional natural gas prices as well as geographic and seasonal natural gas price differentials, which could affect the ability of ~~CERC’s~~their suppliers and customers to meet their obligations or otherwise adversely affect ~~CERC’s~~their liquidity, ~~and~~ results of operations and financial condition.

~~CERC is~~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.~~differentials that impact our business, including transportation and storage, whether through the use of AMAs or other arrangements. Increases in natural gas prices might affect ~~CERC’s~~NGD’s and CES’s ability to collect balances due from ~~its~~their customers and, for NGD, could create the potential for uncollectible accounts expense to exceed the recoverable levels built into ~~CERC’s~~ tariff rates. In addition, a sustained period of high natural gas prices could (i) decrease demand for natural gas in the areas in which

~~CERC operates,~~ NGD and CES operate, thereby resulting in decreased sales and revenues and (ii) increase the risk that ~~CERC’s~~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 ~~CERC’s~~ working capital requirements by increasing the investment that must be made ~~in order~~ to maintain natural gas inventory levels. Additionally, a decrease in natural gas prices could increase the amount of collateral ~~that CERC must provide~~required under ~~its~~ hedging arrangements. AMAs may be subject to regulatory approval, and such agreements may not be renewed or may be renewed with less favorable terms.

A decline in CERC’s credit rating could result in ~~CERC’s~~CERC having to provide collateral under its shipping or hedging arrangements or ~~in order~~ to purchase natural ~~gas.~~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 ~~in order~~ 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.

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

~~A substantial portion of CERC’s~~NGD’s and CES’s revenues isare primarily derived from natural gas sales. Thus, ~~CERC’s~~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. Unusually mild weather in the winter months could diminish our results of operations and harm our financial condition. Conversely, extreme cold weather conditions could increase our results of operations in a manner that would not likely be annually recurring.

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

~~Proposals~~From time to time, proposals have been put forth in some of the states in which ~~CERC~~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 ~~CERC’s~~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 ~~CERC~~NGD and us to comply with competing regulatory requirements.

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

~~CERC competes~~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 ~~CERC~~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 ~~CERC’s~~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 ~~CERC~~NGD and CES as a result of competition may have an adverse impact on ~~CERC’s~~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; the inability of customers to finance projects; risks associated with projects owned or operated; 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, Vectren’s non-utility businesses have supported its utilities pursuant to service contracts by providing infrastructure services. In most instances, Vectren’s 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.

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

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. Vectren, as the parent company, 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. Vectren has not been called upon to satisfy any obligations pursuant to these parental guaranties. As a result of the closing of the Merger, these guaranties would ultimately become obligations of CenterPoint Energy or its subsidiaries.

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

~~We hold~~CenterPoint Energy holds a substantial limited ~~partnership~~partner interest in Enable ~~(55.4%~~(54.0% of ~~Enable’s~~the outstanding common units representing limited ~~partnership~~partner interests in Enable as of December 31, ~~2015)~~2018), as well as 50% of the management rights in ~~Enable’s general partner~~Enable GP and a 40% interest in the incentive distribution rights held by ~~Enable’s general partner. We also hold $363 million~~Enable GP. As of ~~Enable’s~~December 31, 2018, CenterPoint Energy owned an aggregate of 14,520,000 Enable Series A Preferred ~~Units.~~Units representing limited partner interests in Enable. Accordingly, ~~our~~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 ~~we receive~~it receives from Enable and the value of ~~our~~its interests in Enable. Factors that may have a material impact on Enable’s performance and cash distributions, and, hence, the value of ~~our~~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.

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

Both ~~CERC Corp.~~CenterPoint Energy and OGE hold their limited ~~partnership~~partner interests in Enable in the form of ~~both~~ common ~~units~~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 ~~subordinated units.~~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 ~~its general partner~~Enable GP and its affiliates (referred to as “available cash”). The principal difference between Enable’s common units and subordinated units is that in any quarter during the applicable subordination period, holders of the subordinated units are not entitled to receive any distribution of available cash until the common units have received the minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution on common units from prior quarters. If Enable does not pay distributions on its subordinated units, its subordinated units will not accrue arrearages for those unpaid distributions. Accordingly, if Enable is unable to pay its minimum quarterly distribution, the amount of cash distributions we receive from Enable may be adversely affected. Enable may not have sufficient available cash each quarter to enable it (i) to pay distributions on the ~~minimum quarterly distribution.~~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;

the level of competition from other companies offering midstream ~~energy companies;~~services;

adverse effects of governmental and environmental regulation;

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

prevailing economic conditions.

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

the level and timing of its capital expenditures;

the cost of acquisitions;

its debt service requirements and other liabilities;

fluctuations in its working capital needs;

its ability to borrow funds and access capital markets;

restrictions contained in its debt agreements;

the amount of cash reserves established by ~~its general partner;~~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.

23Additionally, 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. 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 ratings 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.

The amount of cash Enable has available for distribution to CenterPoint Energy on its common units ~~including~~and the Enable Series A Preferred Units ~~to us~~ 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 ~~including~~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.

~~We are~~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 ~~CERC Corp.~~CenterPoint Energy and OGE, who each own 50% of the management rights in ~~the general partner of Enable.~~Enable GP. The board of directors of ~~Enable’s general partner~~Enable GP is composed of an equal number of directors appointed by OGE and by ~~us,~~CenterPoint Energy, the president and chief executive officer of ~~Enable’s general partner~~Enable GP and three directors who are independent as defined under the independence standards established by the ~~New York Stock Exchange.~~NYSE. Accordingly, ~~we are~~CenterPoint Energy is not able to exercise control over ~~Enable~~.Enable.

Although weCenterPoint Energy jointly ~~control~~controls Enable with OGE, weCenterPoint Energy may have conflicts of interest with Enable that could subject usit to claims that ~~we have~~CenterPoint Energy has breached ~~our~~its fiduciary duty to Enable and its unitholders.

~~CERC Corp.~~CenterPoint Energy and OGE each own 50% of the management rights in ~~Enable’s general partner,~~Enable GP, as well as limited ~~partnership~~partner interests in Enable, and interests in the incentive distribution rights held by ~~Enable’s general partner.~~Enable GP. CenterPoint Energy also holds Enable Series A Preferred Units. Conflicts of interest may arise between usCenterPoint Energy and Enable and its unitholders. ~~Our~~CenterPoint Energy’s joint control of ~~the general partner 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, weCenterPoint Energy may favor ~~our~~its own interests and the interests of ~~our~~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 usCenterPoint Energy to claims that, in favoring ~~our~~its own interests and those of ~~our~~its affiliates, weCenterPoint 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.

Enable generates a substantial portion of its gross margins under long-term, fee-based agreements. For the year ended December 31, 2015, approximately 81% of Enable’s gross margin was generated from contracts that are fee-based and approximately 56% of its gross margin was attributable to fees associated with firm contracts or contracts with minimum volume commitment features. As these and other contracts expire, Enable may have to negotiate extensions or renewals with existing suppliers and customers or enter into new contracts with other suppliers and customers. Enable may be unable to obtain new contracts on favorable commercial terms, if at all. It also may be unable to maintain the economic structure of a particular contract with an existing customer or the overall mix of its contract portfolio. For example, depending on prevailing market conditions at the time of a contract renewal, gathering and processing customers with fixed-fee or fixed-margin contracts may desire to enter into contracts under different fee arrangements. To the extent Enable is unable to renew or replace its ~~existing~~expiring contracts on terms that are favorable, ~~to it,~~ if at all, or successfully manage its overall contract mix over time, its ~~revenue,~~financial position, results of operations and ~~distributable~~ability to make cash ~~flow~~distributions could be adversely ~~affected.~~affected;

Customers: Enable depends on a small number of customers for a significant portion of its ~~firm~~gathering and processing revenues and its transportation and storage ~~services~~ revenues. The loss of, or reduction in volumes from, these customers ~~could result in a decline in sales of its transportation and storage services and its consolidated financial position, results of operations and its ability to make cash distributions.~~

Enable provides firm transportation and storage services to certain key customers on its system. Its major transportation customers are affiliates of CenterPoint Energy, Laclede, OGE, American Electric Power Company, Inc. and XTO Energy Inc., an affiliate of Exxon Mobil Corporation.

~~The loss of all~~ or ~~even a portion of the interstate or intrastate transportation and storage services for any of these customers,~~ the failure to extend or replace these contracts or the extension or replacement of these contracts on less favorable terms, as a result of competition or otherwise, could result in a decline in sales of its gathering and processing or transportation and storage services and adversely affect Enable’s financial position, results of operations and ~~its~~ ability to make cash ~~distributions.~~distributions;

Third-Party Drilling and Production Decisions: Enable’s businesses are dependent, in part, on the ~~drilling and production decisions of others.~~

Enable’s businesses are dependent on the continued availability of natural gas, NGLs and crude oil production. Enable has no control over the level of drilling activity in its areas of operation, the amount of reserves associated with wells connected to its

systems or the rate at which production from a well declines. In addition, Enable’s cash flows associated with wells currently connected to its systems will decline over time. To maintain or increase throughput levels on its gathering and transportation systems and the asset utilization rates at its natural gas processing plants, Enable’s customers must continually obtain new natural gas and crude oil ~~supplies. The primary factors affecting Enable’s ability to obtain new supplies~~drilling and production market conditions and decisions of natural gas, NGLs and crude oil and attract new customers to its assets are the level of successful drilling activity near these systems, its ability to compete for volumes from successful new wells and its ability to expand capacity as needed. If Enable is not able to obtain new supplies of natural gas, NGLs and crude oil to replace the natural decline in volumes from existing wells, throughput on its gathering, processing, transportation and storage facilities will decline,others, over which ~~could have a material adverse effect on its results of operations and distributable cash flow.~~ Enable has no ~~control over producers or their drilling and production decisions, which are affected by, among other things:~~

~~the availability and cost of capital;~~

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

~~demand for natural gas, NGLs and crude oil;~~

~~levels of reserves;~~

~~geological considerations;~~

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

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

Fluctuations in energy prices can also greatly affect the development of new natural gas, NGLs and crude oil reserves. Drilling and production activity generally decreases as commodity prices decrease. In general terms, the prices of natural gas, crude oil and other hydrocarbon products fluctuate in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond Enable’s control. Because of these factors, even if new natural gas or crude oil reserves are known to exist in areas served by Enable’s assets, producers may choose not to develop those reserves. Declines in natural gas, NGL or crude oil prices can have a negative impact on exploration, development and production activity and, ifFurther, sustained could lead to decreases in such activity. Over the course of 2015 and continuing into 2016, natural gas and crude oil prices have dropped to their lowest levels in over 10 years from a high of $13.31 per MMBtu in July 2008 to $1.63 per MMBtu at December 23, 2015 and $145.31 per barrel in July 2008 to $26.19 per barrel at February 11, 2016, respectively.~~A sustained decline could also lead producers to shut in production from their existing wells. Sustained~~ reductions in exploration or production activity in Enable’s areas of operation and fluctuations in energy prices could lead to further reductions in the utilization of ~~its~~Enable’s systems, which could ~~have a material adverse effect on~~adversely affect its ~~business,~~ financial position, results of operations and ability to make cash distributions.

~~In addition, it~~ It may bealso 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. In addition to capital expenditures to support growth, the steeper production decline curves associated with unconventional resource plays may require Enable to incur higher maintenance capital expenditures relative to throughput over time, which will reduce its distributable cash flow.time;

Because of these and other factors, even if new reserves are known to exist in areas served by Enable’s assets, producers may choose not to develop those reserves. Reductions in drilling activity would result in Enable’s inability to maintain the current levels of throughput on its systems and could have a material adverse effect on its financial position, results of operations and distributable cash flow.

~~Enable’s industry is highly competitive, and increased competitive pressure could adversely affect its financial position, results of operations and distributable cash flow.~~

Competition: Enable competes with similar enterprises, some of which include large energy companies with greater financial resources and access to natural gas, NGL and crude oil supplies, in its respective areas of ~~operation. The principal elements of competition are~~operation, primarily through rates, terms of service and flexibility and reliability of service. Increased competitive pressure in Enable’s ~~competitors include large crude oil, natural gas and petrochemical companies that have greater financial resources and access to supplies of natural gas, NGLs and crude oil than Enable. Some of~~

these competitors may expand or construct gathering, processing, transportation and storage systems that would create additional competition for the services Enable provides to its customers. Excess pipeline capacity in the regions served by Enable’s interstate pipelines could also increase competition and adversely impact Enable’s ability to renew or enter into new contracts with respect to its available capacity when existing contracts expire. In addition, Enable’s customers that are significant producers of natural gas or crude oil may develop their own gathering, processing, transportation and storage systems in lieu of using Enable’s systems. Enable’s ability to renew or replace existing contracts with its customers at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of its competitors and customers. Further, natural gas utilized as a fuel competes with other forms of energy available to end users, including electricity, coal and liquid fuels. Increased demand for such forms of energy at the expense of natural gas could lead to a reduction in demand for natural gas gathering, processing, transportation and transportation services. All of theseindustry, which is already highly competitive, ~~pressures~~ could adversely affect Enable’s financial position, results of operations and ~~distributable~~ability to make cash ~~flow.~~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.

~~Enable’s business plan calls for investment in capital improvements and additions.~~ In Enable’s Form 10-K for the fiscal year ended December 31, ~~2015,~~2018, Enable stated that it expects that its expansion capital ~~will be~~could range from approximately ~~$375~~$325 million to $425 million and its maintenance capital could range from approximately $105 million to $125 million for the year ending December 31, 2016. For example, Enable is currently constructing two cryogenic processing facilities that it plans to connect to its super-header system in Grady and Garvin County, Oklahoma, which Enable expects will add 400 MMcf per day of combined natural gas processing capacity. Enable expects that the first of the two new plants (the Bradley II Plant) will be completed in the second quarter of 2016. Enable expects that the second plant (the Wildhorse Plant), a 200 MMcf per day plant, will be completed in late 2017. Enable also plans to construct natural gas gathering and compression infrastructure to support producer activity.2019;

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

In connection with Enable’s capital investments, Enable may estimate, or engage a third party to estimate, potential reserves in areas to be developed prior to constructing facilities in those areas. To the extent Enable relies on estimates of future production in deciding to construct additions to its systems, those estimates may prove to be inaccurate due to numerous uncertainties inherent in estimating future production. As a result, new facilities may not be able to attract sufficient throughput to achieve expected investment return, which could adversely affect Enable’s results of operations and its ability to make cash distributions. In addition, the construction of additions to existing gathering and transportation assets may require new rights-of-way prior to construction. Those rights-of-way to connect new natural gas supplies to existing gathering lines may be unavailable and Enable may not be able to capitalize on attractive expansion opportunities. Additionally, it may become more expensive to obtain new rights-of-way or to renew existing rights-of-way. If the cost of renewing or obtaining new rights-of-way increases, Enable’s results of operations and its ability to make cash distributions could be adversely affected.

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 ~~its~~ ability to make cash distributions.

~~Enable’s results of operations and its ability to make cash distributions could be negatively affected by adverse movements in the~~ Factors affecting prices ~~of natural gas, NGLs and crude oil depending on factors that~~ are beyond ~~its control. These factors~~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, ~~liquefied 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. Over the course of 2015 and continuing into 2016, natural gas and crude oil prices have dropped to their lowest levels in over 10 years from a high of $13.31 per MMBtu in July 2008 to $1.63 per MMBtu at December 23, 2015 and $145.31 per barrel in July 2008 to $26.19 per barrel at February 11, 2016, respectively.

Further, Enable’s ~~keep-whole~~ natural gas processing arrangements ~~which accounted for 5% of its natural gas processed volumes in 2015,~~ expose it to ~~fluctuations in~~commodity price fluctuations. In 2018, 6%, 27% and 67% 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 pricing spreads between NGL prices and natural gas prices. Under these arrangements, the processor processes raw natural gas to extract NGLs and delivers to the producer the natural gas equivalent Btu value of raw natural gas received from the producer in the form of processed natural gas. The processor retains the processed NGLs and to sell them for its own account. Accordingly, the processor’s cost of natural gas and NGLs is a function of the difference between the value of the NGLs produced and the cost of the processed natural gas used to replace the natural gas equivalent Btu value of those NGLs. Therefore, if natural gas prices increase and NGL prices do not increase by a corresponding amount, the processor has to replace the Btu of natural gasprice at ~~higher prices and cost of natural gas and NGLs sold are negatively affected.~~

Enable’s percent-of-proceeds and percent-of-liquids natural gas processing agreements accounted for 47% of its natural gas processed volumes in 2015. Under percent-of-proceeds processing arrangements, the processor generally purchases unprocessed natural gas from the producer for a purchase price that is based on published natural gas and NGL index prices. The purchase price for unprocessed natural gas is calculated based on a percentage of the quantity of natural gas and NGLs that would result from processing the gas purchased. Accordingly, the processor’s cost of goods sold is a percentage of the index price value of the natural gas and NGLs contained in the unprocessed natural gas. Ifwhich Enable ~~is unable to sell the processed natural gas and NGLs at a higher price than it pays, Enable’s margins from sale of goods are negatively affected. Additionally, if the amount of processed~~sells natural gas or NGLs ~~recovered during processing~~ is less than the ~~amount upon~~cost at which ~~the purchase price was based, Enable’s margins from sale of goods may be negatively affected.~~

~~Under percent-of-liquids processing arrangement, the processor generally~~Enable purchases ~~the NGLs in unprocessed~~ natural gas ~~received from the producer, processes the natural gas, and returns the processed natural gas to the producer. The purchase price for~~or NGLs is based on published NGL index prices and is calculated based on a percentage of the quantity of NGLs that would result from processing the gas. Accordingly, the processor’s cost of goods sold is a percentage of the index price value of NGLs contained in the unprocessed natural gas. If Enable is unable to sell the NGLs recovered during processing at a higher price than it pays,under these arrangements, then Enable’s margins from sale of goods are negatively affected. Additionally, if the amount of NGLs recovered during processing is less than the amount upon which the purchase price was based, Enable’s margins from sale of goods may be negatively affected.

~~At any given time, Enable’s overall portfolio of processing contracts may reflect a net short~~financial position, in natural gas (meaning that it is a net buyer of natural gas) and a net long position in NGLs (meaning that it is a net seller of NGLs). As a result, Enable’s gross margin could be adversely impacted to the extent the price of NGLs decreases in relation to the price of natural gas.

~~Enable has limited experience in the crude oil gathering business.~~

In November 2013, Enable commenced operations on its initial crude oil gathering pipeline system, located in Dunn and McKenzie Counties in North Dakota within the Bakken Shale formation. Additionally in February 2014, Enable executed a crude oil gathering agreement to gather crude oil production through a new system in Williams and Mountrail Counties in North Dakota that commenced operations in the second quarter of 2015. These facilities, which will have a combined capacity of 49,500 barrels per day, are the first crude oil gathering systems that Enable has built and operated. Other operators of gathering systems in the Bakken Shale formation may have more experience in the construction, operation and maintenance of crude oil gathering systems than Enable. This relative lack of experience may hinder Enable’s ability to fully implement its business plan in a timely and cost efficient manner, which, in turn, may adversely affect its results of operations and ~~its~~ ability to make cash distributions ~~to unitholders.~~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 ~~key~~ customers, whether through severe financial problems or otherwise, could adversely affect its ~~cash flow and~~financial position, results of ~~operations.~~

Some of Enable’s customers may experience financial problems that could have a significant effect on their creditworthiness. Severe financial problems encountered by its customers could limit Enable’s ability to collect amounts owed to it, or to enforce performance of obligations under contractual arrangements. In addition, many of Enable’s customers finance their activities through cash flow from operations the incurrence of debt or the issuance of equity. The combination of reduction of cash flow resulting from declines in commodity prices, a reduction in borrowing bases under reserve-based credit facility and ~~the lack of availability of debt or equity financing may result in a significant reduction of its customers’ liquidity and limit their~~ ability to make ~~payment or perform on their obligations to Enable. Furthermore, some of Enable’s customers may be highly leveraged and subject to their~~

own operating and regulatory risks, which increases the risk that they may default on their obligations to Enable. Financial problems experienced by Enable’s customers could result in the impairment of its assets, reduction of its operating cash ~~flows and may also reduce or curtail their future use of its products and services, which could reduce Enable’s revenues.~~distributions;

“Negotiated Rate” Contracts: Enable provides certain transportation and storage services under ~~long-term,~~ fixed-price “negotiated rate” contracts, which are authorized by the FERC, that are not subject to adjustment, even if its cost to perform ~~such~~these services exceeds the revenues received from these contracts. As of December 31, 2018, approximately 44% of Enable’s aggregate contracted firm transportation capacity on EGT and MRT and 45% of its aggregate contracted firm storage capacity on EGT and MRT, was subscribed under such ~~contracts, and, as~~“negotiated rate” contracts. As a result, Enable’s costs could exceed its revenues received under ~~such contracts.~~

~~Enable has been authorized by the FERC to provide transportation~~these contracts, and ~~storage services at its facilities at negotiated rates. Generally, negotiated rates are in excess of the maximum recourse rates allowed by the FERC, but~~if Enable’s costs increase and it is ~~possible that costs~~not able to ~~perform services under “negotiated rate”~~recover any shortfall of revenue associated with its negotiated rate contracts, ~~will exceed the revenues obtained under these agreements. If this occurs, it could decrease~~ the cash flow realized by ~~Enable’s~~its systems could decrease and, therefore, ~~decrease~~ the cash itEnable has available for ~~distribution.~~distribution could also decrease;

Unavailability of December 31, 2015, approximately 60% of Enable’s contracted transportation firm capacity and 44% of its contracted storage firm capacity was subscribed under such “negotiated rate” contracts. These contracts generally do not include provisions allowing for adjustment for increased costs due to inflation, pipeline safety activities or other factors that are not tied to an applicable tracking mechanism authorized by the FERC. Successful recovery of any shortfall of revenue, representing the difference between “recourse rates” (if higher) and negotiated rates, is not assured under current FERC policies.

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 others) become partially or fully unavailable for any reason, Enable’s financial position, results of operations and ~~its~~ ability to make cash distributions could be adversely ~~affected.~~affected; and

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

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

~~Enable does not own all of the land on which its pipelines and facilities have been constructed,~~ and it is therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if it does not have valid rights-of-way or if such rights-of-way lapse or ~~terminate. Enable may obtain the rights to construct and operate~~terminate, which could disrupt its ~~pipelines on land owned by third parties and governmental agencies for a specific period of time. A loss of these rights, through Enable’s inability to renew right-of-way contracts~~operations or ~~otherwise, could cause it to cease operations temporarily or permanently on the affected land, increase~~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 ~~which subject it to additional risks that could have a material adverse effect on the success of these operations and Enable’s financial position and results of operations.~~

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

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

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

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

~~Enable may~~ be ~~unable~~able to control ~~the amount~~decisions, including control of cash ~~it will receive~~distributions to Enable from the joint venture;

Enable may incur liabilities as a result of an action taken by its joint venture ~~partners;~~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 ~~be in a position to~~ take actions contrary to its instructions or requests or contrary to its policies or objectives; and

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

The risks described above or the failure to continue Enable’s joint ventures or to resolve disagreements with its joint venture partners could adversely affect its ability to transact the business that is the subject of such joint venture, which would in turn ~~negatively~~adversely affect Enable’s financial ~~condition,~~position, results of operations and ~~distributable~~ability to make cash ~~flows.~~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 54.0% 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 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.~~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 ~~primarily~~significantly upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund acquisitions and expansion capital expenditures. ~~As a result, to~~To the extent Enable is unable to finance growth externally or through internally generated cash flows, Enable’s cash distribution policy ~~will~~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.~~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.

~~If Enable does not make acquisitions or is unable to make acquisitions on economically acceptable terms, its future growth will be adversely affected.~~

Enable’s growth strategy includes, in part, the ability to make acquisitions that result in an increase in its cash generated from operations. If Enable is unable to make these accretive acquisitions either because: (i) it is unable to identify attractive acquisition targets or it is unable to negotiate purchase contracts on acceptable terms, (ii) it is unable to obtain acquisition financing on economically acceptable terms, or (iii) it is outbid by competitors, then its future growth and ability to increase distributions will be adversely affected.

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

As of December 31, ~~2015,~~2018, Enable had approximately ~~$2.7~~$2.9 billion of long-term debt outstanding, excluding the premiums, discounts and unamortized debt expense on their senior notes, ~~and $363 million of long-term notes payable—affiliated companies due to CERC Corp. In addition, Enable had $236~~$649 million outstanding under its commercial paper program asand $500 million outstanding of ~~December 31, 2015.~~its 2.40% senior notes dues 2019, excluding unamortized debt expense. Enable has a $1.75 billion revolving credit facility for working capital, capital expenditures and other partnership purposes, including acquisitions, ~~of which $1.2 billion was~~with approximately $250 million in borrowings outstanding and $848 million remaining available as of ~~December 31, 2015.~~February 1, 2019. Enable ~~will continue to have~~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 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 ~~business,~~ financial condition, results of operations and ability to make ~~quarterly~~ distributions.

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

permit its subsidiaries to incur or guarantee additional debt;

incur or permit to exist certain liens on assets;

dispose of assets;

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

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

change the nature of its business.

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

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

~~Enable may be unable~~Enable’s businesses are exposed to ~~obtain or renew permits necessary for its operations, which could inhibit its ability to do business.~~

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

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

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

Enable is subject to extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, waste management, wildlife conservation, natural resources and health and safety that could, among other things, delay or increase its costs of construction, restrict or limit the output of certain facilities and/or require additional pollution control equipment and otherwise increase costs. There are significant capital, operating and other costs associated with compliance with these environmental statutes, rules and regulations and those costs may be even more significant in the future.

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

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

Hydraulic fracturing is common practice that is used by many of Enable’s customers to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand, and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. Many of Enable’s customers commonly use hydraulic fracturing techniques in their drilling and completion programs. Hydraulic fracturing typically is regulated by state oil and natural gas commissions. In addition, certain federal agencies have proposed additional laws and regulations to more closely regulate the hydraulic fracturing process. For example, in September 2015, the EPA published updates to new source performance standard requirements that would impose more stringent controls on methane and volatile organic compounds emissions from oil and gas development and production operations, including hydraulic fracturing and other well completion activity. Congress from time to time has considered the adoption of legislation to provide for federal regulation of hydraulic fracturing under the Safe Drinking Water Act and to require disclosure of the chemicals used in the hydraulic fracturing

process. Some states have adopted, and other states are considering adopting, legal requirements that could impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing activities. Local government also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular, in some cases banning hydraulic fracturing entirely. Other governmental agencies, including the DOE and the EPA, have evaluated or are evaluating various other aspects of hydraulic fracturing such as the potential environmental effects of hydraulic fracturing on drinking water and groundwater.

If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where Enable’s oil and natural gas exploration and production customers operate, they could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells, some or all of which activities could adversely affect demand for Enable’s services to those customers.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 ~~have a material adverse effect on~~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 ~~transportation~~crude oil gathering services. ~~The relevant states in which Enable operates include North Dakota, Oklahoma, Arkansas, Louisiana, Texas, Missouri, Kansas, Mississippi, Tennessee and Illinois.~~

The FERC and state regulatory agencies also regulate other terms and conditions of the services Enable may offer. If one of these regulatory agencies, on its own initiative or due to challenges by third parties, were to lower its tariff rates or deny any rate increase or other material changes to the types, or terms and conditions, of service Enable might propose or offer, the profitability of Enable’s pipeline businesses could suffer.

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 ~~were permitted~~ to ~~raise its~~establish new tariff rates for either its natural gas or crude oil pipelines that reflect a ~~particular~~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 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 ~~there might~~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 ~~delay between~~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 ~~the tariff rate increase is approved~~required to prepare applications and ~~the time that the rate increase actually goes into effect,~~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 also limit its profitability. Furthermore, competition from other pipeline systems may prevent Enable from raising its tariff rates even if regulatory agencies permit it to do so. The regulatory agencies that regulate Enable’s systems periodically implement new rules, regulations and terms and conditions of services subject to their jurisdiction. New initiatives or orders may adversely affect the rates charged for Enable’s services or otherwise adversely affect its financial ~~condition,~~position, results of operations and ~~cash flows and its~~ ability to make cash ~~distributions.~~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.

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

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

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

The DOT has adopted regulations requiring pipeline operators to develop integrity management programs for transportation pipelines located in “high consequence areas,” which are those areas where a leak or rupture could do the most harm. The regulations require operators, including Enable, to, among other things:

~~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;~~

~~repair and remediate pipelines as necessary; and~~

~~implement preventive and mitigating action.~~

Although many of Enable’s pipelines fall within a class that is currently not subject to these requirements, it may incur significant cost and liabilities associated with repair, remediation, preventive or mitigation measures associated with its non-exempt pipelines. Should Enable fail to comply with DOT or comparable state regulations, it could be subject to penalties and fines. Also, the scope of the integrity management program and other related pipeline safety programs could be expanded in the future. Such future requirements could adversely affect Enable’s financial position, results of operations and its ability to make cash distributions.

Other Risk Factors Affecting Our Businesses or ~~Our~~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 others:

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

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

possible 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 integrate its systems of internal controls 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 integrate and maintain an effective system of internal controls 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.

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 and have a negative effect on the trading prices of its securities.

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 transmission and distribution system is dependent on not only physical interconnection of our facilities but also on communications among the various components of our system. This reliance on information and communication between and among those components has increased since deployment of smart meters and the intelligent grid. 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 and unauthorized access could also result in the loss, or unauthorized use, of confidential, proprietary or critical infrastructure data or security breaches of other information technology systems that could disrupt operations and critical business functions, adversely affect reputation, increase costs and subject us or Enable to possible legal claims and liability. Further, third parties, including vendors, suppliers and contractors, who perform certain services for us or administer and maintain our sensitive

information, could also be targets of cyber-attacks and unauthorized access. Neither we nor Enable is fully insured against all cyber-security risks, any of which could adversely affect our reputation and could have a material adverse effect on either our or Enable’s results of operations, financial condition and/or cash flows.

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 terrorist activities or otherwise that could disrupt our respective business operations. Any such disruptions could result in significant costs to repair damaged facilities and implement increased security measures, which could have a material adverse effect on either our or Enable’s results of operations, financial condition and/or cash flows.

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

In connection with our business we 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 U.S. regulatory environment surrounding information security and privacy is increasingly demanding. New laws and regulations governing data privacy and the unauthorized disclosure of confidential information, including recent California legislation, pose increasingly complex compliance challenges and potentially 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 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 could adversely impact our reputation and could result in significant costs, fines, litigation. 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, electric generating facilities and electric transmission and distribution systems, and the facilities that support these systems, we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as:

restricting the way we ~~can handle or dispose of~~manage hazardous and non-hazardous wastes;

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) and mercury, and the disposal non-hazardous substances such as coal combustion residuals, among others;

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

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

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

construct or acquire new facilities and equipment;

acquire permits for facility operations;

modify or replace existing and proposed equipment; and

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

future operations. Certain environmental statutes impose strict joint and several liability for costs required to clean, restore and ~~restore~~monitor sites where hazardous substances have been stored, disposed or released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other waste products into the environment.

In April 2015, the EPA finalized its CCR Rule, which regulates ash as nonhazardous 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 relative to the uppermost aquifer. This evaluation indicated that Indiana Electric must cease placing materials into the ash ponds by October 31, 2020 and initiate closure of the ponds thereafter. However, the October 2020 closure deadline, which resulted from a July 2018 amendment to the CCR Rule, is being challenged in the D.C. Circuit. Were the July 2018 amendment vacated, the deadline for Indiana Electric to cease placing materials into the ash ponds and initiate closure could revert to the original April 2019 deadline. However, the CCR Rule allows for a pond to continue receiving materials beyond the deadline for closure upon certification that there is an absence of alternative disposal capacity. Indiana Electric plans to seek such an extension that would allow it to continue to use the ponds through completion of the generation transition plans by December 31, 2023. Failure to obtain this extension 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.

The recent trend in environmental regulation has been to place more restrictions and limitations on activities that may ~~affect~~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 general liability and property insurance in place to cover certain of our facilities in amounts that we consider appropriate. Such policies are subject to certain limits and deductibles and do not include business interruption coverage. Insurance coverage may not be available in the future at current costs or on commercially reasonable terms, and the insurance proceeds received for any loss of, or any damage to, any of our facilities may not be sufficient to restore the loss or damage without negative impact on our results of operations, financial condition and cash flows.

In common with other companies in its line of business that serve coastal regions, ~~CenterPoint~~ Houston Electric does not have insurance covering its transmission and distribution system, other than substations, because ~~CenterPoint~~ Houston Electric believes it to be cost ~~prohibitive. In the future, CenterPoint~~prohibitive and believes insurance capacity to be limited. Historically, Houston ~~may not be~~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, or~~otherwise. In the future, any such recovery may not be ~~timely~~ granted. Therefore, ~~CenterPoint~~ 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 the gathering, processing, transportation and storage of natural gas and crude oil, including:~~

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

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

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

~~ruptures, fires and explosions; and~~

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

We and OGE currently have general liability and property insurance in place to cover certain of Enable’s facilities in amounts that we consider appropriate. Such policies are subject to certain limits and deductibles. 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 Enable’s operations. A natural disaster or other hazard affecting the areas in which Enable operates could have a material adverse effect on 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.

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

damage to pipelines and plants, related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires, earthquakes 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 hazards that could also result in personal injury and loss of life, pollution and suspension of operations.

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

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

Under some circumstances, ~~we, CenterPoint Houston and CERC~~the Registrants could incur liabilities associated with assets and businesses ~~we, CenterPoint Houston and CERC~~ no longer ~~own.~~owned by them. These assets and businesses were previously owned by Reliant Energy, ~~Incorporated (Reliant Energy),~~ a predecessor of ~~CenterPoint~~ 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 ~~Holdings, Inc. (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), ~~that company and its~~those companies and/or their subsidiaries assumed liabilities associated with various assets and businesses ~~Reliant Energy~~ transferred to ~~them. RRI also~~them and agreed to indemnify, and cause the applicable transferee subsidiaries to indemnify, us and our subsidiaries, including CenterPoint Houston and CERC, with respect to liabilities associated with the transferred assets and businesses. Thesecertain indemnity ~~provisions were intended to place sole financial responsibility on RRI and its subsidiaries for all liabilities associated with the current and historical businesses and operations of RRI, regardless~~agreements of the Registrants. Such indemnities have applied in various asbestos and other environmental matters that arise from time ~~those liabilities arose. If RRI (now GenOn) were unable~~ to ~~satisfy a liability that has been so assumed in circumstances in which Reliant Energy~~time and ~~its subsidiaries were not released from~~cases such as the ~~liability in connection with the transfer, we, CenterPoint Houston or CERC could be responsible for satisfying the liability.~~

Prior to the distribution of our ownership in RRI to our shareholders, CERC had guaranteed certain contractual obligations of what became RRI’s trading subsidiary. When the companies separated, RRI agreed to secure CERC against obligations under the guarantees RRI had been unable to extinguish by the time of separation. Pursuant to such agreement, as amended in December 2007, RRI (now GenOn) agreed to provide to CERC cash or letters of credit as security against CERC’s obligations under its remaining guarantees for demand charges under certain gas transportation agreements if and to the extent changes in market conditions expose CERC to a risk of loss on those guarantees based on an annual calculation, with any required collateral to be posted each December. The undiscounted maximum potential payout of the demand charges under these transportation contracts, which will be in effect until 2018, was approximately $27 million as of December 31, 2015. Based on market conditions in the fourth quarter of 2015 at the time the most recent annual calculation was made under the agreement, GenOn was not obligated to post any security. If GenOn should fail to perform the contractual obligations, CERC could have to honor its guarantee and, in such event, any collateral then provided as security may be insufficient to satisfy CERC’s obligations.

If GenOn were unable to meet its obligations, it could consider, among various options, restructuring under the bankruptcy laws, in which event GenOn might not honor its indemnification obligations and claims by GenOn’s creditors might be made against us as its former owner.

~~Reliant Energy and RRI (GenOn’s predecessor) are named as defendants in a number of lawsuits~~litigation arising out of sales of natural gas in California and other ~~markets. Although these matters relate to~~markets (further appellate review of the ~~business and operations of GenOn, claims against Reliant Energy have been made on grounds that include liability of Reliant Energy as a controlling shareholder of GenOn’s predecessor, and~~last remaining case involving CES, a subsidiary of CERC Corp., has been stayed pending approval of a settlement agreement following the Ninth Court of Appeals’ reversal in August 2018 of the district court’s grant of summary judgment in favor of CES). In June 2017, GenOn and various affiliates filed for protection under Chapter 11 of the U.S. Bankruptcy Code. CenterPoint Energy, CERC and CES submitted proofs of claim in the bankruptcy proceedings to protect their indemnity rights. In October 2018, CES, GenOn, and the plaintiffs reached an agreement to settle all claims against CES and CES’s indemnity claims against GenOn, subject to approvals by the bankruptcy court and the federal district court. In December 2018, GenOn completed its reorganization and emerged from Chapter 11, and in January 2019, the bankruptcy court approved the settlement between CES and GenOn. If the settlement agreement between CES, GenOn and the plaintiffs is ~~a defendant in a case now pending in~~not approved by the federal district court, ~~in Nevada. We, CenterPoint Houston or CERC~~CES could incur liability ~~if claims in one or more of these lawsuits were successfully asserted against us, CenterPoint Houston or CERC~~ and ~~indemnification from GenOn were determined to be unavailable or if GenOn were unable to satisfy indemnification obligations owed with respect to those claims.~~

In connection with the organization and capitalization of Texas Genco (now an affiliate of NRG), Reliant Energy and Texas Genco entered into a separation agreement in which Texas Genco assumed liabilities associated with the electric generation assets Reliant Energy transferred to it. Texas Genco also agreed to indemnify, and cause the applicable transferee subsidiaries to indemnify, us and our subsidiaries, including CenterPoint Houston, with respect to liabilities associated with the transferred assets and businesses. In many cases the liabilities assumed were obligations of CenterPoint Houston, and CenterPoint Houston was not released by third parties from these liabilities. The indemnity provisions were intended generally to place sole financial responsibility on Texas Genco and its subsidiaries for all liabilities associated with the current and historical businesses and operations of Texas Genco, regardless of the time those liabilities arose. If Texas Genco were unable to satisfy a liability that had

~~been so assumed or indemnified against, and provided we or Reliant Energy had not been released from the liability in connection with the transfer, CenterPoint Houston could~~ be responsible for satisfying ~~the liability.~~it.

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 weCenterPoint 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 ~~us.~~

~~We or our subsidiaries have been named, along with numerous others, as a defendant~~CenterPoint Energy, and in ~~lawsuits filed by a number of individuals who claim injury due to exposure to asbestos. Some~~certain of the claimants have worked at locations owned by us, but most existing claims relate to facilities previously owned by our subsidiaries. We anticipate that additional claims like those received may be asserted in the future. Under the terms of the arrangements regarding separation of the generating business from us and our sale of that business to an affiliate of NRG, ultimate financial responsibility for uninsured losses from claims relating to the generating businessasbestos lawsuits CenterPoint Energy has ~~been assumed by the NRG affiliate, but we have~~ agreed to continue to defend such claims to the extent they are covered by insurance maintained by ~~us,~~CenterPoint Energy, subject to reimbursement of the costs of such defense by ~~the~~an NRG affiliate.

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

We and Enable are subject to cyber and physical security risks related to breaches in the systems and technology used (i) to manage operations and other business processes and (ii) to protect sensitive information maintained in the normal course of business. The operation of our electric transmission and distribution system is dependent on not only physical interconnection of our facilities, but also on communications among the various components of our system. As we deploy smart meters and the intelligent grid, reliance on communication between and among those components increases. Similarly, the distribution of natural gas to our customers and the gathering, processing and transportation of natural gas or other commodities from Enable’s gathering, processing and pipeline facilities, are dependent on communications among Enable’s facilities and with third-party systems that may be delivering natural gas or other commodities into or receiving natural gas and other products from Enable’s facilities. Disruption of those communications, whether caused by physical disruption such as storms or other natural phenomena, by failure of equipment or technology, or by manmade events, such as cyber-attacks or acts of terrorism, may disrupt our ability or Enable’s ability to conduct operations and control assets. Cyber-attacks could also result in the loss of confidential or proprietary data or security breaches of other information technology systems that could disrupt operations and critical business functions, adversely affect reputation, and subject us or Enable to possible legal claims and liability. Neither we nor Enable is fully insured against all cyber-security risks, any of which could have a material adverse effect on either our, or Enable’s, results of operations, financial condition and cash flows. In addition, electrical distribution and transmission facilities and gas distribution and pipeline systems may be targets of terrorist activities that could disrupt either our or Enable’s ability to conduct our respective businesses and have a material adverse effect on either our or Enable’s results of operations, financial condition and cash flows.

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

In connection with our business we collect and retain personally identifiable information of our customers, shareholders and employees. Our customers, shareholders and employees expect that we will adequately protect their personal information, and the United States regulatory environment surrounding information security and privacy is increasingly demanding. A significant theft, loss or fraudulent use of customer, shareholder, employee or CenterPoint Energy data by cyber-crime or otherwise could adversely impact our reputation and could result in significant costs, fines and litigation.

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

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

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

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

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

labor disputes;

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

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

catastrophic events such as fires, earthquakes, explosions, leaks, floods, droughts, hurricanes, terrorism, pandemic health events or other similar ~~occurrences.~~occurrences, which may require participation in mutual assistance efforts by us or other utilities to assist in power restoration efforts.

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

Our 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 ~~our~~ 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. 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 ~~business is~~and Enable’s businesses are dependent on ~~our ability to recruit, retain,~~recruiting, retaining and ~~motivate~~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 ~~business.~~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 ~~services~~ or Enable’s services.

Regulatory agencies have from time to time considered adopting new legislation ~~including the modification of~~and/or modifying existing laws and regulations, to reduce ~~emissions of~~ GHGs, and there ~~has been~~continues to be a wide-ranging policy and regulatory debate, both nationally and internationally, regarding the potential impact of ~~these gases~~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.

Due to the electric generating facilities acquired in the Merger, CenterPoint Energy is subject to the requirements of the CPP, which requires a 32% reduction in carbon emissions from 2005 levels. While implementation of the CPP remains uncertain due to the February 2016 U.S. Supreme Court stay delaying implementation during court challenges and an October 2017 proposed rule from the EPA which, if finalized, would result in the CPP’s repeal, as written the CPP may substantially affect both the costs and operating characteristics of CenterPoint Energy’s fossil fuel generating plants and NGD business. In August 2018, the EPA proposed a CPP replacement rule, the Affordable Clean Energy (ACE) rule, which, if finalized could similarly impact the costs of CenterPoint Energy’s fossil fuel generating plants. In addition to regulatory risk, we may be subject to climate change lawsuits which could result in substantial penalties or damages. 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.

Following a finding by the EPA that certain GHGs represent an endangerment to human health, the EPA adopted two sets of rules regulating GHG emissions under the Clean Air Act, one that requires a reduction in emissions of GHGs from motor vehicles and another that regulates emissions of GHGs from certain large stationary sources. The EPA has also expanded its existing GHG emissions reporting requirements. These permitting and reporting requirements could lead to further regulation of GHGs by the EPA. As a distributor and transporter of natural gas, or a consumer of natural gas in its pipeline and gathering businesses, ~~CERC’s~~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. ~~Our electric~~Further, Indiana Electric’s current generating facilities substantially rely on coal for their operations. Additionally, Houston Electric’s and Indiana Electric’s transmission and distribution business, in contrast to some electric utilities, does not generate electricity and thus is not directly exposed to the risk of high capital costs and regulatory uncertainties that face electric utilities that burn fossil fuels to generate electricity. Nevertheless, CenterPoint Houston’sbusinesses’ revenues could be adversely affected to the extent any resulting regulatory action has the effect of reducing consumption of electricity by ultimate consumers within its service territory. Likewise, incentives to conserve energy or use energy sources other than natural gas could result in a decrease in demand for our services.

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

~~To the extent~~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 our businesses may be adversely impacted, though we believe any such impacts are likely to occur very gradually and hence would be difficult to quantify with specificity. To the extent global climate change resultsthat result in warmer temperatures in our service territories, financial results from our ~~natural gas distribution~~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 ~~transmission~~gathering, processing and ~~field services~~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 ~~tornadoes.~~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. Decreased energy use may also require us to retire current infrastructure that is no longer needed.

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

On December 22, 2017, President Trump signed into law the TCJA, which resulted in significant changes to federal tax laws effective January 1, 2018, including, but not limited to, a reduction in the corporate income tax rate.

For Houston Electric, Indiana Electric and NGD, federal income tax expense is included in the rates approved by state commissions and local municipalities and charged by those utilities to consumers. When Houston Electric, Indiana Electric and NGD have general rate cases and other periodic rate adjustments, we expect the lower corporate tax expense resulting from the TCJA (which includes determining the treatment of EDIT), along with other increases and decreases in our revenue requirements, to be incorporated into Houston Electric’s, Indiana Electric’s and NGD’s future rates. Nevertheless, regulators may require us to respond to the TCJA in other ways, including through faster recoveries of reductions in federal income tax expense, accounting orders to reflect a liability to return to customers in future rate proceedings, accelerated returns to consumers of previously collected deferred federal income taxes, increased funding of infrastructure upgrades, or offsets of future rate increases. The effect on us of any potential return of tax savings resulting from the TCJA to consumers may differ depending on how each regulatory body requires us to return such savings. We can provide no assurances on how any regulatory body will ultimately require us to act. As such, we are currently unable to determine the impact of these potential regulatory actions in response to the enactment of the TCJA, which may adversely affect our results of operations, financial condition and cash flows. For further information, 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.

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

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 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 is expected to publish finalized regulations in 2019, for both natural gas and hazardous liquids pipelines, that will significantly extend and expand 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 final rules may also impose new requirements for certain unregulated pipelines, including gathering lines. 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.

~~CenterPoint Energy has~~We have risks associated with aging infrastructure assets. The age of certain of our assets may result in a need for replacement, or higher level of maintenance costs as a result of our risk based federal and state compliant integrity management programs. Failure to achieve timely recovery of these expenses could adversely impact revenues and could result in increased capital expenditures or expenses. 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. ~~There are seven~~We have several separate bargaining units, ~~in CenterPoint Energy,~~ each with a unique collective bargaining ~~agreement.~~ agreement described below:

The collective bargaining agreement with ~~the International Brotherhood of Electrical Workers~~IBEW Local 66 ~~and the two~~related to employees of Houston Electric is scheduled to expire in May 2020;

The collective bargaining agreements with ~~Professional Employees International Union Local 12~~USW Locals 13-227 and 13-1 related to NGD’s employees in Texas are scheduled to expire in ~~March~~June 2022 and ~~May of 2016. Two additional~~July 2022, respectively;

The collective bargaining agreements ~~will be~~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;

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 was scheduled to expire in June 2019 but was renegotiated in ~~2017.~~ January 2019 with the ratification of a new three-year labor agreement.

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. We expect that new~~rapidly and increasing in complexity. New technologies will emerge or grow that may be superior to, or may not be compatible with, some of our existing technologies, and may require us to make significant expenditures so that we can continue to provide cost-effective and reliable methods 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 consumption. As these technologies become a more cost-competitive option over time, whether through cost effectiveness or government incentives and subsidies, certain customers may choose to meet their own energy needs and subsequently decrease usage of our systems and services. 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 ~~delivery.~~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 and to offer, on a timely basis, reliable services that meet customer demands and evolving industry standards. If we fail to adapt successfully to any technological change or obsolescence, or 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, ~~and~~ 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 ~~successful~~completed or ~~may result in completed acquisitions that do not~~ perform as ~~anticipated.~~expected.

From time to time, we and Enable have made and may continue to make acquisitions or divestitures of businesses and ~~assets.~~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. In addition, any~~acceptable, or the expected benefits of completed acquisitions may not be realized fully or at all, or may not be realized in the anticipated timeframe. If we or Enable are unable to make acquisitions or if those acquisitions do not perform as anticipated, our and Enable’s future growth may be adversely affected.

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

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

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

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

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

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

~~Our business could be negatively affected as a result of the actions of activist shareholders.~~

Publicly traded companies have increasingly become subject to campaigns by activist investors advocating corporate actions such as financial restructuring, increased borrowing, special dividends, stock repurchases or even sales of assets or the entire company. It is possible that activist shareholders may attempt to effect such changes or acquire control over us. Responding to proxy contests and other actions by activist shareholders can be costly and time-consuming, disrupt our operations and divert the attention of our board of directors and senior management from the pursuit of business strategies, which could adversely affect our results of operations and financial condition. Additionally, perceived uncertainties as to our future direction as a result of shareholder activism or changes to the composition of the board of directors may lead to the perception of a change in the direction of the business, instability or lack of continuity. This may be exploited by our competitors, cause concern to our current or potential customers, and make it more difficult to attract and retain qualified personnel.

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

WeThe Registrants are subject to numerous legal proceedings, the most significant of which are summarized in ~~Note14~~Note 16 to the Registrants’ respective consolidated financial statements.

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 allege violations of Sections 14(a) of the Exchange Act and SEC Rule 14a-9 on the grounds that the Proxy Statement filed on June 18, 2018 was materially incomplete because it omitted material information concerning the Merger. The lawsuits also seek certification as class actions. In August 2018, the seven lawsuits were consolidated, ~~financial statements.~~ and the Court denied the plaintiffs’ request for a preliminary injunction. The plaintiffs filed their Consolidated Amended Class Action Complaint on October 29, 2018, which Defendants have moved to dismiss and which motion remains pending. On December 28, 2018, two plaintiffs voluntarily dismissed their lawsuits. The defendants believe that the allegations asserted are without merit and intend to vigorously defend themselves against the claims raised.

Litigation is subject to many uncertainties, and wethe Registrants cannot predict the outcome of ~~individual~~all matters with assurance. Final resolution of these matters may require additional expenditures over an extended period of time that may be in excess of established insurance or reserves and may have a material adverse effect on ~~our~~the Registrants’ financial results.

We are exposed to risks related to reduction in energy consumption due to factors including unfavorable economic conditions in our service territories.

Our businesses are affected by ~~the~~reduction in energy consumption due to factors including economic climate in our service territories, energy efficiency initiatives and use of alternative technologies, which could impact our ability to grow our customer base and our rate of growth. Growth in customer accounts and growth of customer usage each directly influence demand for electricity and the need for additional delivery facilities. Customer growth and customer usage are affected by a number of factors outside our control, such as mandated energy efficiency measures, demand-side management goals, distributed generation resources and economic and demographic conditions, such as population changes, job and income growth, housing starts, new business formation and the overall level of economic activity.

Declines in demand 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 ~~reduced energy consumption by our customers. Some economic sectors important~~future material impairment charges to ~~our customer base may be affected.~~ write-down the carrying value of certain assets, including goodwill, to their respective fair values.

For example, ~~our~~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. ~~Given the significant decline in energy and commodity prices in 2015, the rate of growth in~~Although Houston, Texas has a diverse economy, employment in the energy industry remains important with overall Houston ~~has declined.~~ employment growing at a moderate rate in 2018. 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 ~~rate~~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 negative public ~~perceptions.~~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, 2018 and does not include Vectren and its subsidiaries.

Character of Ownership

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

Electric Transmission & Distribution (CenterPoint Energy and Houston Electric)

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

Midstream Investments (CenterPoint Energy)

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

Other Operations (CenterPoint Energy and CERC)

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


Item 3.	Legal Proceedings

For a discussion of material legal and regulatory proceedings affecting ~~us,~~the Registrants as of December 31, 2018, 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 ~~14(d)~~16(d) to ~~our~~the consolidated financial statements, which information is incorporated herein by reference.


Item 4.	Mine Safety Disclosures

Not applicable.

PART II

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


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

CenterPoint Energy

As of February 12, ~~2016~~2019, ~~our~~CenterPoint Energy’s common stock was held by approximately ~~34,130~~28,987 shareholders of record. ~~Our~~CenterPoint Energy’s common stock is listed on the ~~New York~~NYSE and Chicago Stock ~~Exchanges~~Exchange and is traded under the symbol “CNP.”

~~The following table sets forth the high and low closing prices of the common stock of CenterPoint Energy on the New York Stock Exchange composite tape during the periods indicated, as reported by~~ ~~Bloomberg,~~ ~~and the cash dividends declared in these periods.~~

Market Price

Dividend
Declared
High Low Per Share
2015
First Quarter $ 0.2475
January 2 $ 23.63

March 31 $ 20.41

Second Quarter $ 0.2475
April 15 $ 21.31

June 30 $ 19.03

Third Quarter $ 0.2475
August 14 $ 19.92

September 29 $ 17.53

Fourth Quarter $ 0.2475
October 22 $ 19.13

December 10 $ 16.14

2014
First Quarter $ 0.2375
January 3 $ 22.81

February 21 $ 24.48

Second Quarter $ 0.2375
April 7 $ 23.39

June 30 $ 25.54

Third Quarter $ 0.2375
July 1 $ 25.38

August 6 $ 23.56

Fourth Quarter $ 0.2375
November 10 $ 25.38

December 15 $ 21.54

~~The closing market price of our common stock on~~ ~~December 31, 2015~~ ~~was $18.36 per share.~~

The amount of future cash dividends will be subject to determination based upon ~~our~~CenterPoint Energy’s results of operations and financial condition, ~~our~~ future business prospects, any applicable contractual restrictions and other factors that ~~our board~~CenterPoint Energy’s Board of ~~directors~~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 ~~board of directors.~~consolidated financial statements.

On ~~January 20, 2016, our board of directors declared a regular quarterly cash dividend of~~ ~~$0.2575~~ ~~per share, payable on~~ ~~March 10, 2016~~ ~~to shareholders of record on~~ ~~February 16, 2016~~.

Repurchases of Equity Securities

During the quarter ended December 31, ~~2015~~2018, none of ~~our~~CenterPoint Energy’s equity securities registered pursuant to Section 12 of the Securities Exchange Act of 1934 were purchased by or on behalf of usCenterPoint Energy or any ~~of our~~ “affiliated purchasers,” as defined in Rule 10b-18(a)(3) under the Securities Exchange Act of 1934.

Houston Electric

As of February 12, 2019, all of Houston Electric’s 1,000 outstanding common shares are held by Utility Holding, LLC, a wholly-owned subsidiary of CenterPoint Energy.

CERC

As of February 12, 2019, all of CERC Corp.’s 1,000 outstanding shares of common stock are 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 ~~our~~CenterPoint Energy’s consolidated financial condition and consolidated results of operations and should be read in conjunction with ~~our~~CenterPoint Energy’s consolidated financial statements and the related notes in Item 8 of this report.

Year Ended December 31,
2015 2014 2013 2012 2011 (4)
(in millions, except per share amounts)
Revenues $ 7,386
$ 9,226
$ 8,106
$ 7,452
$ 8,450

Equity in Earnings (Losses) of Unconsolidated Affiliates (1,633 ) (1) 308
(2) 188
(3) 31
30

Income (Loss) before Extraordinary Item (692 ) 611
311
417
770

Extraordinary Item, net of tax —
—
—
—
587

Net income (loss) $ (692 ) $ 611
$ 311
$ 417

$ 1,357

Basic earnings (loss) per common share:
Income (Loss) before Extraordinary Item $ (1.61 ) $ 1.42
$ 0.73
$ 0.98
$ 1.81

Extraordinary Item, net of tax —
—
—
—
1.38

Basic earnings (loss) per common share $ (1.61 ) $ 1.42
$ 0.73
$ 0.98

$ 3.19

Diluted earnings (loss) per common share:
Income (Loss) before Extraordinary Item $ (1.61 ) $ 1.42
$ 0.72
$ 0.97
$ 1.80

Extraordinary Item, net of tax —
—
—
—
1.37

Diluted earnings (loss) per common share $ (1.61 ) $ 1.42
$ 0.72
$ 0.97

$ 3.17

Cash dividends declared per common share $ 0.99
$ 0.95
$ 0.83
$ 0.81
$ 0.79

Dividend payout ratio n/a 67 % 114 %
83 %
44 % (5)
Return on average common equity (17 )% 14 % 7 % 10 % 21 % (5)
Ratio of earnings to fixed charges 2.67
2.79
2.42
2.29
2.96
(5)
At year-end:

Book value per common share $ 8.05
$ 10.58
$ 10.09
$ 10.09
$ 9.91

Market price per common share 18.36
23.43
23.18
19.25
20.09

Market price as a percent of book value 228 % 221 % 230 % 191 % 203 %
Total assets $ 21,334
$ 23,200
$ 21,870
$ 22,871
$ 21,703

Short-term borrowings 40
53
43
38
62

Transition and system restoration bonds, including current maturities 2,674
3,046
3,400
3,847
2,522

Other long-term debt, including current maturities 6,100
5,758
4,914
5,910
6,603

Capitalization:

Common stock equity 28 % 34 % 34 % 31 % 32 %
Long-term debt, including current maturities 72 % 66 % 66 % 69 % 68 %
Capitalization, excluding transition and system restoration bonds:

Common stock equity 36 % 44 % 47 % 42 % 39 %
Long-term debt, excluding transition and system restoration bonds, and including current maturities 64 % 56 % 53 % 58 % 61 %
Capital expenditures $ 1,575
$ 1,402
$ 1,272
$ 1,188
$ 1,191



	Year Ended December 31,
	2018			2017				2016			2015				2014
	(in millions, except per share amounts)
Revenues	$	10,589		$	9,614			$	7,528		$	7,386			$	9,226
Equity in earnings (losses) of unconsolidated affiliates, net	307			265				208			(1,663		)	(2)	308
Income (loss) available to common shareholders	333			1,792			(1)	432			(692		)		611
Basic earnings (loss) per common share	0.74			4.16				1.00			(1.61		)		1.42
Diluted earnings (loss) per common share	0.74			4.13				1.00			(1.61		)		1.42

Cash dividends paid per common share	$	1.11		$	1.07			$	1.03		$	0.99			$	0.95
Dividend payout ratio	150		%	26		%		103		%	n/a				67		%
Return on average common equity	5		%	44		%		12		%	(17		)%		14		%
At year-end:
Book value per common share	$	16.08		$	10.88			$	8.04		$	8.05			$	10.58
Market price per common share	28.23			28.36				24.64			18.36				23.43
Market price as a percent of book value	176		%	261		%		306		%	228		%		221		%
Percentage of common units owned representing limited partner interests in Enable	54.0		%	54.1		%		54.1		%	55.4		%		55.4		%
Total assets (3) (4)	$	27,009		$	22,736			$	21,829		$	21,290			$	23,150
Short-term borrowings	—			39				35			40				53
Securitization Bonds, including current maturities (3)	1,435			1,868				2,278			2,667				3,037
Other long-term debt, including current maturities (3)	7,729			6,933				6,279			6,063				5,717
Capitalization:
Common stock equity	47		%	35		%		29		%	28		%		34		%
Long-term debt, including current maturities	53		%	65		%		71		%	72		%		66		%
Capitalization, excluding Securitization Bonds:
Common stock equity	51		%	40		%		36		%	36		%		44		%
Long-term debt, excluding Securitization Bonds, and including current maturities	49		%	60		%		64		%	64		%		56		%
Capital expenditures	$	1,720		$	1,494			$	1,406		$	1,575			$	1,402

(1)

~~As of~~Net income for the year ended December 31, ~~2015, we owned approximately 55.4%~~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 ~~limited partner interests in Enable Midstream Partners, LP (Enable), an unconsolidated subsidiary that we account for on an equity basis.~~ impacts of the TCJA implementation.


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


~~(2)~~(3)	AsAmounts for 2014 and 2015 have been recast to reflect adoption of December 31, 2014, we owned approximately 55.4% of the limited partner interests in Enable and 0.1% of Southeast Supply Header (SESH), each an unconsolidated subsidiary, that we accounted for on an equity basis.ASU 2015-03.


~~(3)~~	Following the formation of Enable on May 1, 2013, Enable owned substantially all of our former Interstate Pipelines and Field Services business segments, except for our retained 25.05% interest in SESH. As of December 31, 2013, we owned approximately 58.3% of the limited partner interests in Enable.


(4)	~~2011 Income before Extraordinary Item includes a $224 million after-tax ($0.53~~Total assets as of December 31, 2018 include cash and ~~$0.52 per basic and diluted share, respectively) return on true-up balance related to a portion~~cash equivalents of ~~interest on the appealed true-up amount.~~$4.2 billion.


~~(5)~~	~~Calculated using Income before Extraordinary Item.~~


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 ~~our~~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.

Because the Merger closed after December 31, 2018, unless otherwise specifically indicated, the Registrants’ respective consolidated financial statements and notes thereto and the discussion of the Registrants’ financial condition, results of operations, tax payments and other financial and business-related information herein do not include or take into account Vectren and its subsidiaries, the closing of the Merger and the effects of the Merger. See Note 4 to the consolidated financial statements for further information related to the Merger.

OVERVIEW

Background

~~We are~~CenterPoint Energy, Inc. is a public utility holding ~~company. Our~~company and owns interests in Enable as described below. CenterPoint Energy’s operating subsidiaries, Houston Electric and CERC Corp., own and operate electric transmission and distribution ~~facilities~~ and natural gas distribution facilities and ~~own interests in Enable Midstream Partners, LP (Enable) as described below. Our indirect wholly-owned subsidiaries include:~~supply natural gas to commercial and industrial customers and electric and natural gas utilities.

~~CenterPoint Energy~~ Houston Electric ~~LLC (CenterPoint Houston), which~~ engages in the electric transmission and distribution business in the Texas Gulf Coast area that includes the city of Houston; and

~~CenterPoint Energy Resources~~CERC Corp. ~~(CERC Corp. and, together with its subsidiaries, CERC), which~~(i) owns and operates natural gas distribution ~~systems. A wholly-owned subsidiary of CERC Corp.~~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.~~ utilities in over 30 states through its wholly-owned subsidiary, CES.

As of December 31, ~~2015, CERC Corp. also~~2018, CenterPoint Energy, indirectly through CNP Midstream, owned approximately ~~55.4%~~54.0% of the common units representing limited partner interests in Enable, ~~which~~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.

~~Business~~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 further discussion of the Merger, see Note 4 to the consolidated financial statements.

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 ~~business segments.~~reportable segments, which are listed below. We also discuss our liquidity, capital resources and critical accounting policies. We are first and foremost an energy delivery company and it is our intention to remain focused on these segments of the energy business. The results of our business operations are significantly impacted by weather, customer growth, economic conditions, cost management, competition, rate proceedings before regulatory agencies and other actions of the various regulatory agencies to whose jurisdiction we are ~~subject. Our electric~~subject, among other factors.

Electric transmission and distribution services are subject to rate regulation and are reported in the Electric Transmission & Distribution ~~business~~reportable segment, as are impacts of generation-related stranded costs and other true-up balances recoverable by the regulated electric utility. For further information about the Electric Transmission & Distribution reportable segment, see “Business — Our ~~natural~~Business — Electric Transmission & Distribution” in Item 1 of Part I of this report.

Natural gas distribution services are also subject to rate regulation and are reported in the Natural Gas Distribution ~~business~~reportable segment. 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.

The 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.

The results of ~~our~~the Midstream Investments reportable segment are dependent upon the results of Enable, which are driven primarily by the volume of natural gas, ~~natural gas liquids (NGLs)~~NGLs and crude oil that Enable gathers, processes and transports across its systems and other factors as discussed below under “— Factors Influencing ~~Our~~ Midstream ~~Investments Segment.~~Investments.” ~~A summary of our reportable business segments as of~~ ~~December 31, 2015~~ ~~is set forth below:~~

~~Electric Transmission & Distribution~~

Our electric transmission and distribution operations provide electric transmission and distribution services to retail electric providers (REPs) serving over 2.3 million metered customers in a 5,000-square-mile area of the Texas Gulf Coast that has a population of approximately six million people and includes the city of Houston.

~~On behalf of REPs,~~ CenterPoint Houston delivers electricity from power plants to substations, from one substation to another and to retail electric customers in locations throughout CenterPoint Houston’s certificated service territory. The Electric Reliability Council of Texas, Inc. (ERCOT) serves as the regional reliability coordinating council for member electric power systems in Texas. ERCOT membership is open to consumer groups, investor and municipally-owned electric utilities, rural electric cooperatives, independent generators, power marketers, river authorities and REPs. The ERCOT market represents approximately 90% of the

demand for power in Texas and is one of the nation’s largest power markets. Transmission and distribution services are provided under tariffs approved by the Public Utility Commission of Texas (Texas Utility Commission).

~~Natural Gas Distribution~~

CERC owns and operates our regulated natural gas distribution business (NGD), which engages in intrastate natural gas sales to, and natural gas transportation and storage for, approximately 3.4 million residential, commercial and industrial customers in Arkansas, Louisiana, Minnesota, Mississippi, Oklahoma and Texas.

~~Energy Services~~

~~CERC’s operations also include non-rate regulated natural gas sales to, and transportation and storage services for, commercial and industrial customers in 23 states in the central United States.~~

~~Midstream Investments~~

We have a significant equity investment in Enable, an unconsolidated subsidiary that owns, operates and develops natural gas and crude oil assets. Our Midstream Investments segment includes equity earnings associated with the operations of Enable.

Energy’s Other Operations

~~Our other operations business~~ reportable segment includes office buildings and other real estate used ~~in our~~for business operations, home repair protection plans through a third party and other corporate support operations ~~which~~that support ~~all of our~~

CenterPoint Energy’s business operations. CERC’s Other Operations reportable segment includes unallocated corporate costs and inter-segment eliminations.

EXECUTIVE SUMMARY

~~Factors Influencing Our Businesses and Industry Trends~~

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

Factors Influencing Our Businesses and Industry Trends

We are an energy delivery company. The majority of our revenues are generated from the ~~sale of natural gas and the~~ transmission and delivery of electricity and the sale of natural gas by our ~~subsidiaries. We do~~subsidiaries, Houston Electric and CERC, respectively. The Electric Transmission & Distribution reportable segment does not own or operate electric generating facilities or make retail sales to end-use electric customers. To assess our financial performance, our management primarily monitors operating income and cash flows, among other things, from our ~~business~~reportable segments. Within these broader financial measures, we monitor margins, operation and maintenance expense, interest expense, capital spending and working capital requirements. In addition to these financial measures, we also monitor a number of variables that management considers important to ~~the operation of~~ our ~~business~~reportable segments, including the number of customers, throughput, use per customer, commodity prices and heating and cooling degree days. ~~We also~~From an operational standpoint, we monitor safety factors, system reliability ~~safety factors~~ and customer satisfaction to gauge our performance.

To the extent adverse economic conditions affect our suppliers and customers, results from our energy delivery businesses may suffer. For example, our 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. Reduced demand and lower energy prices could lead to financial pressure on some of our customers who operate within the energy industry and impact the growth rate of our customer base. Given the significant decline in energy and commodity prices in 2015, the rate of growth in employment in Houston, which had been greater than the national average, has declined and is now more in line with the national average. We expect this trend to continue in the foreseeable future. Also, adverse economic conditions, coupled with concerns for protecting the environment, may cause consumers to use less energy or avoid expansions of their facilities, resulting in less demand for our services.

Performance of our Electric Transmission & Distribution and Natural Gas Distribution business segments is significantly influenced by the number of customers and energy usage per customer. Weather conditions can have a significant impact on energy usage, and we compare our results on a weather adjusted basis. In 2015, our Houston service area experienced some of the mildest temperatures on record during November and December. Every state in which we distribute natural gas had a warmer than normal winter in 2015. Historically, NGD has utilized weather hedges to help reduce the impact of mild weather on its financial results. However, NGD did not enter a weather hedge for the 2015–2016 winter season as a result of NGD’s Minnesota division implementing a full decoupling pilot in July 2015. We also have various rate mechanisms in place that help to mitigate the impact of abnormal weather on our financial results. In 2014, we experienced a colder than normal January and February and milder

temperatures for the rest of the year, including the summer months, in the Houston area. In 2013, we experienced a colder than normal spring and very cold weather in November and December in Houston and all of the states in which we have gas customers. Our long-term national trends indicate customers have reduced their energy consumption, and reduced consumption can adversely affect our results. However, due to more affordable energy prices and continued economic improvement in the areas we serve, the trend toward lower usage has slowed in some of the areas we serve. In addition, in many of our service areas, particularly in the Houston area and in Minnesota, we have benefited from a growth in the number of customers that also tends to 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 gas distribution rates.

Our Energy Services business segment contracts with customers for transportation, storage and sales of natural gas on an unregulated basis. Its operations serve customers in the central United States. The segment benefits from favorable price differentials, either on a geographic basis or on a seasonal basis. While this business utilizes financial derivatives to hedge its exposure to price movements, it does not engage in speculative or proprietary trading and maintains a low value at risk level, or VaR, to avoid significant financial exposures. In 2015 and 2014, Energy Services exhibited strong commercial and industrial customer results while capitalizing on asset optimization opportunities created by basis volatility. Extreme cold weather in 2014 also increased throughput and margin from our weather sensitive customers.

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 ~~in order~~ 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, ~~companies like us~~we may not be able to obtain certain types of external financing or may be required to accept terms less favorable than they would otherwise accept. For that reason, we seek to maintain adequate liquidity for our businesses through existing credit facilities and prudent refinancing of existing debt.

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 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. Although Houston, Texas has a diverse economy, employment in the energy industry remains important with overall Houston employment growing at a moderate rate in 2018.

Also, adverse economic conditions, coupled with concerns for protecting the environment and increased availability of alternate energy sources, may cause consumers to use less energy or avoid expansions of their facilities, resulting in less demand for our services. To the extent population growth is affected by lower energy prices and there is financial pressure on 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. Primarily due to the cyclical correction of over-building in multifamily residential construction, residential meter growth for Houston Electric remained at approximately 1.6% in 2018. Based on, among other things, the anticipated completion of more apartment units in 2019, management expects residential meter growth to increase this year to 2%, in line with long-term trends.

Performance of the Electric Transmission & Distribution 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.

Overall, in 2018 the Houston area experienced weather that was much closer to normal relative to 2017. Although January, April and November experienced colder than normal weather, this was offset during the remaining months of the year due to warmer than normal weather. While overall rainfall was higher than normal in 2018, it did not rise to the record rainfall levels experienced in 2017 that occurred largely due to Hurricane Harvey. After two years of consistently warmer than normal weather in 2016 and 2017 in our NGD territories, 2018 experienced a return to normal weather in the first and fourth quarters.

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 2017-2018 and 2018-2019 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, 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.

With respect to upcoming general rate cases, as required by a settlement related to the TCJA filed with the PUCT in February 2018, Houston Electric expects to make its comprehensive base rate filing by the April 30, 2019 deadline. The amount and other terms of the rate filing have not been established at this time. There is no guarantee that current rates will continue while that case is pending, or that the rate case will result in rates that fully recover Houston Electric’s costs or enable it to earn a reasonable return on its invested capital. The results of this rate case may significantly impact Houston Electric’s business.

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. At the end of 2017, a weather-driven spike in natural gas prices caused the accrual of unusually high unrealized mark-to-market income, which substantially reversed in the first quarter of 2018 as natural gas prices normalized.

The regulation of natural gas pipelines and related facilities by federal and state regulatory agencies affects ~~our~~CERC’s business. In accordance with natural gas pipeline safety and integrity regulations, ~~we are~~CERC is making, and will continue to make, significant capital investments in ~~our~~its service territories, which are necessary to help operate and maintain a safe, reliable and growing natural gas system. ~~Our~~CERC’s compliance expenses may also increase as a result of preventative measures required under these regulations. Consequently, new rates in the areas ~~we serve~~it serves are necessary to recover these increasing costs.

~~We expect to make contributions to our pension plans aggregating approximately $8 million in 2016 but may need to make larger contributions in subsequent years.~~ Consistent with the regulatory treatment of ~~such~~pension costs, ~~we can~~the Registrants defer the amount of pension expense that differs from the level of pension expense included in ~~our~~the Registrants’ base rates for ~~our~~the Electric Transmission & Distribution ~~business~~reportable segment and Natural Gas Distribution ~~business~~reportable segment in Texas. CenterPoint Energy expects to contribute a minimum of approximately $93 million to its pension plans in 2019.

Additional Considerations Relating to Vectren (CenterPoint Energy)

The following additional considerations affect the business and industry of the utility and non-utility businesses and operations of Vectren that CenterPoint Energy acquired upon consummation of the Merger. With respect to Vectren’s utilities, its natural gas operations (comprised of Indiana Gas, VEDO and SIGECO’s natural gas distribution business) provide natural gas distribution and transportation services to nearly 67% of Indiana and about 20% of Ohio, primarily in the west-central area. Its electric operations (comprised of Indiana Electric) provide electric transmission and distribution services to southwestern Indiana, and include 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.

Similar to Houston Electric and CERC’s NGD, sales of natural gas and electricity to residential and commercial customers 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 Vectren’s utilities have implemented conservation programs. In Vectren’s two Indiana natural gas 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. The Ohio natural gas service territory has a straight fixed variable rate design for its residential customers. This rate design mitigates approximately 90% of the Ohio service territory’s weather risk and risk of decreasing consumption specific to its small customer classes. While Indiana Electric has neither a normal temperature adjustment mechanism nor a decoupling mechanism, rate designs provide for a lost margin recovery mechanism that operates in tandem with conservation initiatives.

Vectren’s non-utility operations include Infrastructure Services and energy services, provided through ESG. Infrastructure Services, through its wholly-owned subsidiaries, provides underground pipeline and repair services to many utilities, including Vectren’s 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.

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, but opportunities for large transmission pipeline construction projects will continue to be pursued and Infrastructure Services is well positioned to do this work. The timing and recurrence of these large transmission projects is less predictable and may create volatility in its year-over-year results.

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.

Factors Influencing ~~Our~~ Midstream Investments ~~Segment~~(CenterPoint Energy)

The results of ~~our~~CenterPoint Energy’s Midstream Investments reportable segment are ~~primarily~~ 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, which depends~~systems. These volumes depend significantly on the level of production from natural gas wells connected to ~~its~~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, as production~~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.

~~Oil~~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 ~~gas producers’ willingness to engage~~results of operations may differ materially from its expectations.

Enable’s business is impacted by commodity prices, which have declined and otherwise experienced significant volatility in ~~new~~recent years. Commodity prices impact the drilling ~~is determined by a number of factors, the most important of which are the prevailing~~ and ~~projected prices~~production of natural gas ~~NGLs~~ and crude oil in the ~~cost~~areas served by Enable’s systems. In addition, Enable’s processing arrangements expose it to ~~drill and operate a well, the availability and cost of capital and environmental and government regulations. Commodity~~commodity price changes impact the commodity-based portion of Enable’s gross margin, its producer customers’ decisions to drill and complete wells and its transportation and storage customers decisions to contract capacity on Enable’s system. Prices of natural gas, crude oil, and NGLs have historically experienced periods of significant volatility. Enable’s results are also impacted by the price differentials between receipt and delivery points on its systems.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. The prices of crude oil, NGLs and natural gas have continued to decline significantly. Over the course of 2015 and continuing into 2016, natural gas and crude oil prices have dropped to their lowest levels in over 10 years from a high of $13.31 per MMBtu in July 2008 to $1.63 per MMBtu at December 23, 2015 and $145.31 per barrel in July 2008 to $26.19 per barrel at February 11, 2016, respectively.

Should lower commodity prices persist, or should commodity prices decline further, Enable’s future volumes and cash flows may be negatively impacted. The level of drilling is expected to positively correlate with long-term trends in commodity prices. Similarly, production levels nationally and regionally generally tend to positively correlate with drilling activity.

~~Over the past several years, there has been a fundamental shift in U.S.~~Enable’s long-term view is that natural gas and crude oil production ~~towards tight gas formations and shale plays. The emergence of these plays and advancements~~ in technology have been crucial factors that have allowed producers to efficiently extract significant volumes of natural gas and crude oil. Recently, declining crude oil, natural gas and NGL prices have resulted in decreases in current and anticipated crude oil and natural gas drilling activity. Should lower prices and producer activity persist for a sustained period or should prices and producer activity decline further, Enable’s future volumes and cash flows may be negatively impacted. To maintain and increase throughput volumes on its systems, Enable must continue to contract its capacity to shippers, including producers and marketers. Enable’s transportation and storage systems compete for customers based on the type of service a customer needs, operating flexibility, receipt and delivery points and geographic flexibility and available capacity and price. To maintain and increase Enable’s transportation and storage volumes, it must continue to contract its capacity to shippers, including producers, marketers, local distribution companies, power generators and industrial end users.

U.S. will increase. Natural gas continues to be a critical component of energy ~~supply and~~ demand in the ~~United States. Over the long term,~~U.S. Enable’s management believes that the prospects for continued natural gas demand are favorable and will be driven by population and economic growth, as well as the continued displacement of coal-fired ~~electricity generation~~power plants by natural gas-fired ~~electricity generation~~power plants due to the ~~low prices~~price of natural gas and stricter government environmental regulations on the mining and burning of coal. According to the U.S. Energy Information Administration (EIA), demand for natural gas in the electric power sector is projected to increase from approximately 8.2 Tcf in 2013 to approximately 9.4 Tcf in 2040, with a portion of the growth attributable to the retirement of 37 gigawatts of coal-fired capacity by 2020. The EIA also predicts that low natural gas prices will lead to the increase of natural gas consumption in the industrial sector and to the United States becoming a new exporter of natural gas by mid-2017. However, the EIA expects growth in natural gas consumption for power generation, exploration and in the industrial sector to be partially offset by decreased usage in the residential sector. Enable’s management believes that increasing consumption of natural gas over the long term in these sectors will continue to drive demand for Enable’s natural gas gathering, processing, transportation and storage services.

Enable may access the capital markets to fund expansion capital expenditures. Historically, unit prices of midstream master limited partnerships have experienced periods of volatility. In addition, because Enable’s common units are yield-based securities, rising market interest rates could impact the relative attractiveness of Enable’s common units to investors. Further, fluctuations in energy and commodity prices can create volatility in Enable’s common unit prices, which could impact investor appetite for its common units. Volatility in energy and commodity prices, as well as other macro economic factors could impact the relative attractiveness of Enable’s debt securities to investors. As a result of capital market volatility, Enable may be unable to issue equity or debt on satisfactory terms, or at all, which may limit its ability to expand its operations or make future acquisitions.

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

Significant Events

~~Impairment of Equity Investment.~~Merger with Vectren. ~~We recognized a loss of $1,633 million from our investment~~On February 1, 2019, pursuant to the Merger Agreement, CenterPoint Energy consummated the previously announced Merger and acquired Vectren for approximately $6 billion in Enable for the year ended December 31, 2015. This loss included impairment charges totaling $1,846 million composed of the impairment of our investment in Enable of $1,225 million and our share, $621 million, of impairment charges Enable recorded for goodwill and long-lived assets.cash. For further discussion of the ~~impairment,~~Merger, see Note 94 to ~~our~~the consolidated financial statements.

~~Brazos Valley Connection Project.~~Credit Facility. ~~In April 2015,~~On October 5, 2018, CenterPoint ~~Houston filed a Certificate of Convenience and Necessity (CCN) application with~~Energy terminated all remaining commitments by lenders to provide the ~~Texas Utility Commission seeking approval to construct the Brazos Valley Connection (CenterPoint Houston’s portion of the Houston region transmission project).~~Bridge Facility, which resulted in increased aggregate commitments under CenterPoint Houston proposed 32 alternative routes for the project in the application, including one route (the Recommended Route) that CenterPoint Houston identified in the application as best meeting the routing criteria used by the Texas Utility Commission in the route selection portion of CCN proceedings. The hearing on CenterPoint Houston’s CCN application was divided into two phases, a route-selection phase and a need phase. The route selection hearing was held on August 17 and 18, 2015. The hearing on the need for the line was held on September 2 and 3, 2015. On January 15, 2016, the Texas Utility Commission issued an order finding that the evidence presented by CenterPoint Houston, ERCOT, and others established the need for the project and approving a CCN for CenterPoint Houston to construct the Brazos

~~Valley Connection using a modified version of the Recommended Route. A request for rehearing was filed with respect~~Energy’s revolving credit facility. For further information, see Note 14 to the Texas Utility Commission’s route selection decision. That request for rehearing will be automatically deemed denied by operation of law on March 10, 2016, unless the Texas Utility Commission acts on the request before that date. The Texas Utility Commission’s order provided an estimated range of approximately $270–$310 million for the capital costs for the Brazos Valley Connection. The actual cost will depend on factors including land acquisition costs, material and construction costs and landowner elections permitted under the Texas Utility Commission’s order. CenterPoint Houston expects to complete construction of the Brazos Valley Connection by mid-2018.

~~Transmission Cost of Service (TCOS).~~On June 26, 2015, CenterPoint Houston filed an application with the Texas Utility Commission for an interim update of its TCOS seeking an increase in annual transmission revenues based on an incremental increase of $87.6 million in total rate base. The Texas Utility Commission approved CenterPoint Houston’s application in the third quarter of 2015, and rates became effective August 17, 2015, resulting in an increase of $13.7 million in annual transmission revenues.

On October 1, 2015, CenterPoint Houston filed an application with the Texas Utility Commission for an interim update of its TCOS seeking an increase in annual transmission revenues based on an incremental increase of $107.6 million in total rate base. The Texas Utility Commission approved CenterPoint Houston’s application in the fourth quarter of 2015, and rates became effective November 23, 2015, resulting in an increase of $16.8 million in annual transmission revenue.

~~Distribution Cost Recovery Factor (DCRF).~~On April 6, 2015, CenterPoint Houston filed an application with the Texas Utility Commission for a DCRF interim rate adjustment to account for changes in certain distribution-invested capital since its 2010 rate case. The application requested (i) an increase in annual distribution revenue of $16.7 million based on an increase in rate base from January 1, 2010 through December 31, 2014 of $417 million; and (ii) that rates become effective September 1, 2015.

On June 19, 2015, an unopposed settlement agreement was filed providing for an increase in annual distribution revenue of $13.0 million, subject to final Texas Utility Commission approval. The Texas Utility Commission approved the settlement agreement on July 30, 2015. Rates became effective September 1, 2015.

~~Texas Coast Rate Case.~~On March 27, 2015, NGD filed a Statement of Intent with each of the 49 cities and unincorporated areas within its Texas Coast service territory for a $6.8 million annual revenue increase. This increase was based on a rate base of $132.3 million and a return on equity (ROE) of 10.25%. On July 6, 2015, the parties agreed to a settlement providing for a $4.9 million annual increase to rates, an ROE of 10.0%, 54.5% equity and authorized overall rate of return of 8.23%. This settlement resolved six outstanding cases on appeal: one on remand at the Railroad Commission of Texas (Railroad Commission) and five cost of service adjustment (COSA) appeals at the district court. The Railroad Commission unanimously approved the settlement on August 25, 2015. Rates were implemented in September 2015.

~~Arkansas Formula Rate Review Plan (FRP) Legislation.~~ On March 30, 2015, HB 1655 was signed by Governor Hutchinson and became Act 725 (the Act). This legislation introduces a FRP mechanism for utilities and requires that the Arkansas Public Service Commission (APSC) approve a FRP if requested by a utility and allows a utility to use a projected test year. The Act establishes certain parameters, including the use of an earnings band 50 basis points above and below the allowed return on equity and annual rate changes not to exceed 4% of prior year revenues per rate class. The details of a FRP that were not established by the Act are being defined during the rate proceeding currently in process.consolidated financial statements.

~~Arkansas Rate Case.~~Enable Midstream Spin. On ~~August 17, 2015, NGD filed a Notice~~September 4, 2018, CERC completed the Internal Spin of ~~Intent~~its equity investment in Enable and Enable GP. For further information regarding the Internal Spin, see Note 11 to ~~File a general rate case with~~ the APSC. The rate case was filed on November 10, 2015 seeking a $35.6 million increase in revenue requirement and a 10.3% ROE. A procedural schedule has been established with a hearing scheduled for July 12, 2016. A final determination by the APSC is expected in the third quarter of 2016.consolidated financial statements.

~~Minnesota Rate Case.~~In August 2015, NGD filed a general rate case with the Minnesota Public Utilities Commission (MPUC) requesting an annual increase of $54.1 million. On September 10, 2015, the MPUC approved an interim increase of $47.8 million in revenues effective October 2, 2015, subject to a refund. The MPUC is expected to issue a final decision in mid-2016 with final rates effective by the end of 2016.

~~Tender Offer for AOL Inc.~~Equity Offerings. On August 22, 2018, CenterPoint Energy completed an offering of its Series A Preferred Stock. On October 1, 2018, CenterPoint Energy completed concurrent equity offerings of depositary shares, each representing a 1/20th interest in a share of Series B Preferred Stock, and Common Stock.On May 26, 2015, Verizon Communications, Inc. (Verizon) initiated a tender offer to purchase all outstanding shares of AOL Inc. common stock (AOL Common) for $50 per share, in which we tendered all of our shares of AOL Common for $32 million. Verizon acquired For further information about the remaining eligible shares through a merger, which closed on June 23, 2015. In accordance with the terms of the Zero-Premium Exchangeable Subordinated Notes due 2029 (ZENS), we remitted $32 million to ZENS holders in July 2015, which reduced contingent principal. As a result, we recorded a reduction in

the indexed debt securities derivative liability of $18 million, a reduction in the indexed debt balance of $7 million and a loss of $7 million. As of December 31, 2015, the reference shares for each ZENS note consisted of 0.5 share of Time Warner Inc. common stock (TW Common), 0.125505 share of Time Warner Cable Inc. (TWC) common stock (TWC Common) and 0.0625 share of Time Inc. common stock (Time Common).

~~Exercise of Put Right.~~On June 30, 2015, we closed our put right with respect to our remaining interest in Southeast Supply Header, LLC (SESH) and contributed to Enable our remaining 0.1% interest in SESH in exchange for 25,341 limited partner units of Enable. No cash payment was required to be made pursuantequity offerings, see Note 13 to the ~~Enable formation agreements in connection with our exercise.~~consolidated financial statements.

Debt ~~Repayments.~~Transactions. In ~~June 2015, we repaid our $200~~February 2018, Houston Electric issued $400 million ~~6.85% Senior Notes using proceeds from our commercial paper program.~~aggregate principal amount of general mortgage bonds. In March 2018, CERC issued $600 million aggregate principal amount of unsecured senior notes. In October ~~2015, we repaid our $69~~2018, CenterPoint Energy issued $1.5 billion aggregate principal amount of senior notes. In January 2019, Houston Electric issued $700 million ~~4.9% pollution control bonds using proceeds from our commercial paper program.~~aggregate principal amount of general mortgage bonds. For further information about the Registrants’ debt issuance in 2018 and to date in 2019, see Note 14 to the consolidated financial statements.

~~Retirement of Bonds.~~Regulatory Proceedings. ~~In November 2015, we retired $740 million of tax-exempt municipal bonds that had been held for remarketing.~~For details related to pending and completed regulatory proceedings during 2018 and to date in 2019, see “—Liquidity and Capital Resources — Regulatory Matters” below.

~~Private Placement.~~On January 28, 2016, we entered into a purchase agreement with Enable pursuant to which we agreed to purchase in a private placement (Private Placement) an aggregate of 14,520,000 10% Series A Fixed-to-Floating Non-Cumulative Redeemable Perpetual Preferred Units representing limited partner interests in Enable (Series A Preferred Units) for a cash purchase price of $25.00 per Series A Preferred Unit. The Private Placement closed on February 18, 2016. In connection with the Private Placement, Enable redeemed approximately $363 million of notes scheduled to mature in 2017 payable to a wholly-owned subsidiary of CERC Corp. We used the proceeds from this redemption for our investment in the Series A Preferred Units.

~~Continuum Acquisition.~~ On January 29, 2016, CenterPoint Energy Services (CES), our indirect, wholly-owned subsidiary, announced an agreement to acquire the retail commercial and industrial businesses of Continuum Energy Services (Continuum), a Tulsa and Houston-based company, for $77.5 million plus working capital. The transaction is conditioned upon the receipt of certain third party consents and approvals. We expect the transaction to close by the end of the first quarter of 2016.

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 ~~we receive~~CenterPoint Energy receives from Enable, Enable’s ability to redeem the Enable Series A Preferred Units in certain circumstances and the value of ~~our~~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;

◦

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


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


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


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


◦	changes in tax status; and


◦	access to debt and ~~growth~~equity capital; ~~and~~


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

~~state~~CenterPoint Energy’s expected benefits of the Merger and ~~federal legislative~~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 ~~regulatory actions~~realize anticipated benefits and the risk that the credit ratings of the combined company 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, health care reform, financial reform, tax legislation and actions regarding the rates charged by our regulated businesses;its subsidiaries may be different from what CenterPoint Energy expects;

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

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;

timely and appropriate rate actions that allow recovery of costs and a reasonable return on investment, including Houston Electric’s anticipated rate case in 2019, the outcome of which may not result in expected rates or recovery of costs;

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 the effects of geographic and seasonal commodity price differentials on CERC and Enable;

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

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 those related to global climate change;

the impact of unplanned facility outages;

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

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

our ability to control operation and maintenance costs;

~~actions by credit rating agencies;~~

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

the investment performance of ~~our~~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 ~~interest rates or~~ 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 ~~any future hurricanes or natural disasters;~~Hurricane Harvey;

~~our~~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 a reduction of CenterPoint Energy’s interest in Enable, if any, whether through its decision to sell a portion of the Enable common units it owns in the public equity markets or otherwise, subject to certain limitations), which weCenterPoint Energy and Enable cannot assure ~~you~~ will be completed or will have the anticipated benefits to ~~us;~~CenterPoint Energy or Enable;

acquisition and merger activities involving us or our ~~competitors;~~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 ability of GenOn Energy, Inc. (formerly known as RRI Energy, Inc., Reliant Energy, Inc. and Reliant Resources, Inc.), a wholly-owned subsidiary of NRG Energy, Inc. (NRG), and its subsidiaries to satisfy their obligations to us, including indemnity obligations, or obligations in connection with the contractual arrangements pursuant to which we are their guarantor;

~~the~~ outcome of litigation;

the ability of REPs, including REP affiliates of NRG and Vistra Energy ~~Future Holdings~~Corp., formerly known as TCEH Corp., to satisfy their obligations to usCenterPoint Energy and ~~our subsidiaries;~~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 timing and outcome of any audits, disputes and other proceedings related to taxes;

the effective tax rates;

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

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

CENTERPOINT ENERGY CONSOLIDATED RESULTS OF OPERATIONS

~~All dollar amounts in the tables that follow are in millions, except for per share amounts.~~


										Year Ended December 31,
	Year Ended December 31,									2018			2017			2016
	2015			2014			2013			(in millions, except per share amounts)
Revenues	$	7,386		$	9,226		$	8,106		$	10,589		$	9,614		$	7,528
Expenses	6,453			8,291			7,096			9,758			8,478			6,505
Operating Income	933			935			1,010			831			1,136			1,023
Gain (Loss) on Marketable Securities	(93		)	163			236			(22		)	7			326
Gain (Loss) on Indexed Debt Securities	74			(86		)	(193		)	(232		)	49			(413		)
Interest and Other Finance Charges	(352		)	(353		)	(351		)	(361		)	(313		)	(338		)
Interest on Transition and System Restoration Bonds	(105		)	(118		)	(133		)
Equity in Earnings (Losses) of Unconsolidated Affiliates	(1,633		)	308			188
Other Income, net	46			36			24
Income (Loss) Before Income Taxes	(1,130		)	885			781
Interest on Securitization Bonds										(59		)	(77		)	(91		)
Equity in Earnings of Unconsolidated Affiliates										307			265			208
Other Income (Expense), net										50			(4		)	(29		)
Income Before Income Taxes										514			1,063			686
Income Tax Expense (Benefit)	(438		)	274			470			146			(729		)	254
Net Income (Loss)	$	(692	)	$	611		$	311
Net Income										368			1,792			432
Preferred Stock dividend requirement										35			—			—
Income Available to Common Shareholders										$	333		$	1,792		$	432

Basic Earnings (Loss) Per Share	$	(1.61	)	$	1.42		$	0.73
Basic Earnings Per Common Share										$	0.74		$	4.16		$	1.00

Diluted Earnings (Loss) Per Share	$	(1.61	)	$	1.42		$	0.72
Diluted Earnings Per Common Share										$	0.74		$	4.13		$	1.00

~~2015~~2018 Compared to ~~2014~~2017

Net Income. WeCenterPoint Energy reported ~~a net loss~~income available to common shareholders of ~~$692~~$333 million (~~$(1.61)~~ ($0.74 per diluted common share) for ~~2015~~2018 compared to ~~net income of $611~~$1,792 million ($~~1.42~~4.13 per diluted common share) for ~~the same period in 2014.~~2017.

The decrease in ~~net~~ income available to common shareholders of ~~$1,303~~$1,459 million was primarily due to the following key factors:

an $875 million increase in income tax expense, resulting from a ~~$1,941~~reduction in income tax expense of $1,113 million ~~decrease~~due to tax reform in ~~equity earnings of unconsolidated affiliates, which included impairment charges of $1,846 million,~~2017, discussed further in Note 915 to ~~our~~the consolidated financial ~~statements;~~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 ~~$256~~$29 million increase in ~~the loss~~losses on ~~our~~ marketable securities.

These decreases were partially offset by:

•a ~~$712~~$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;

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

~~a $160 million increase in the gain on our indexed debt securities;~~

~~a $13~~•an $18 million decrease in interest expense related to ~~our transition~~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 ~~system restoration bonds;~~

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

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.

2017 Compared to 2016

Net Income. CenterPoint Energy reported income available to common shareholders of $1,792 million ($4.13 per diluted common share) for 2017 compared to $432 million ($1.00 per diluted common share) for 2016.

The increase in income available to common shareholders of $1,360 million was primarily due to the following key factors:

a $983 million decrease in income tax expense, resulting from a reduction in income tax expense of $1,113 million due to tax reform, discussed further in Note 15 to the consolidated financial statements, offset by a $130 million increase in income tax expense primarily due to higher net income year over year;

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

a $113 million increase in operating income discussed below by reportable segment in Results of Operations by Reportable Segment;

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

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

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

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

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

These increases were partially offset by:

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

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

Income Tax Expense. CenterPoint Energy reported an effective tax rate of (69%) and 37% for the years ended December 31, 2017 and 2016, respectively. The effective tax rate of (69%) was primarily due to 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%. See Note 15 to the consolidated financial statements for a more in-depth discussion of the 2017 impacts of the TCJA.

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,
	2018			2017			2016
	(in millions)
Revenues	$	3,234		$	2,998		$	3,059
Expenses	2,609			2,361			2,407
Operating Income	625			637			652
Interest and other finance charges	(138		)	(128		)	(126		)
Interest on Securitization Bonds	(59		)	(77		)	(91		)
Other expense, net	(3		)	(8		)	(10		)
Income before income taxes	425			424			425
Income tax expense (benefit)	89			(9		)	149
Net income	$	336		$	433		$	276

2018 Compared to 2017

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

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

an $10 million increase in interest expense due to higher outstanding other ~~income.~~long-term debt.

These decreases to 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. WeHouston Electric reported an effective tax rate of ~~38.8%~~21% and ~~31.0%~~(2%) for the years ended December 31, ~~2015~~2018 and ~~2014,~~2017, respectively. The higher effective tax rate of 38.8% is primarily due to lower earnings from the impairment of our investment in Enable. The impairment loss reduced the deferred tax liability on our investment in Enable. The effective tax rate of ~~31.0% for 2014~~21% is primarily due to ~~a $29 million tax benefit recognized upon completion of a tax basis balance sheet review and a $13 million reversal of previously accrued taxes as a result of final positions taken~~the reduction in the ~~2013~~federal corporate income tax ~~returns. We determined~~rate from 35% to 21% effective January 1, 2018 as prescribed by the ~~impact~~TCJA and the amortization of ~~the $29 million adjustment was not material to any prior period or the year ended December 31, 2014.~~EDIT.

~~2014~~2017 Compared to ~~2013~~2016

Net Income. WeHouston Electric reported net income of ~~$611~~$433 million ~~($1.42 per diluted share)~~ for ~~2014~~2017 compared to ~~$311~~$276 million ~~($0.72 per diluted share)~~for 2016.

The increase of $157 million in net income was primarily due to the following key factors:

a $158 million decrease in income tax expense due to a reduction in the corporate income tax rate resulting from the TCJA; and

a $1 million increase in TDU operating income resulting from a $1 million decrease discussed below in Results of Operations by Reportable Segment, which was more than offset by increased usage of $2 million, primarily due to a return to more normal weather, which was not offset by the weather hedge loss recorded on CenterPoint Energy.

This increase in net income was partially offset by a $2 million increase in interest expense due to higher outstanding other long-term debt.

Income Tax Expense. Houston Electric reported an effective tax rate of (2%) and 35% for the ~~same period~~years ended December 31, 2017 and 2016, respectively. The effective tax rate of (2%) was primarily due to 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%. See Note 15 to the consolidated financial statements for a more in-depth discussion of the 2017 impacts of the TCJA.

CERC CONSOLIDATED RESULTS OF OPERATIONS

CERC’s results of operations are affected by seasonal fluctuations in ~~2013.~~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,
	2018			2017			2016
	(in millions)
Revenues	$	7,343		$	6,603		$	4,454
Expenses	7,121			6,136			4,113
Operating Income	222			467			341
Interest and other finance charges	(122		)	(123		)	(122		)
Other expense, net	(8		)	(25		)	(20		)
Income from continuing operations before income taxes	92			319			199
Income tax expense (benefit)	22			(265		)	81
Income from continuing operations	70			584			118
Income from discontinued operations, net of tax	138			161			127
Net Income	$	208		$	745		$	245

2018 Compared to 2017

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

2017 Compared to 2016

Net Income. CERC reported net income of $745 million for 2017 compared to net income of $245 million for 2016.

The increase in net income of ~~$300~~$500 million was primarily due to the following key factors:

a ~~$196~~$346 million decrease in income tax expense, resulting from a reduction in income tax expense of $396 million due to tax reform, discussed ~~below;~~further in Note 15 to the consolidated financial statements, offset by a $50 million increase in income tax expense primarily due to higher income from continuing operations year-over-year;

a ~~$120~~$126 million increase in ~~equity earnings~~operating income discussed below in Results of ~~unconsolidated affiliates;~~

~~a $107 million decrease in the loss on our indexed debt securities;~~

~~a $13 million decrease in interest expense;~~Operations by Reportable Segment; and

a ~~$12~~$34 million increase in ~~other income.~~income from discontinued operations, net of tax, discussed further in Notes 11 and 15 to the consolidated financial statements.

These increases were partially offset by:

a ~~$75~~$5 million decrease in ~~operating~~miscellaneous other non-operating income ~~(discussed below by segment);~~included in Other Income, net shown above; and

a ~~$73~~$1 million ~~decrease~~increase in interest expense due to the ~~gain on our marketable securities.~~issuance of $300 million of unsecured senior notes and higher weighted average commercial paper interest rates discussed further in Note 14 to the consolidated financial statements.

Income Tax Expense. ~~We reported an~~CERC’s effective tax rate ~~of 31.0%~~reported on income from continuing operations was (83%) and ~~60.2%~~41% for the years ended December 31, ~~2014~~2017 and ~~2013,~~2016, respectively. The effective tax rate of ~~31.0% for 2014~~(83%) on income from continuing operations is primarily due to ~~a $29 million tax benefit recognized upon completion~~the remeasurement of ~~a tax basis balance sheet review and a $13 million reversal of previously accrued taxes~~CERC’s ADFIT liability as a result of ~~final positions taken in~~ the ~~2013 tax returns. We determined the impact~~enactment of the ~~$29 million adjustment was not material to any prior period or~~TCJA on December 22, 2017, which reduced the ~~year ended December 31, 2014. The effective~~U.S. corporate income tax rate ~~of 60.2% for 2013 is primarily attributable~~from 35% to ~~a net $196 million charge to deferred tax expense due~~21%. See Note 15 to the ~~formation of Enable. For more information, see Note 13 to our~~ consolidated financial ~~statements.~~ statements for a more in-depth discussion of the 2017 impacts of the TCJA.

RESULTS OF OPERATIONS BY ~~BUSINESS~~REPORTABLE SEGMENT

As of December 31, 2018, reportable segments by Registrant are as follows:



Registrant	Electric Transmission & Distribution	Natural Gas Distribution	Energy Services	Midstream Investments	Other Operations
CenterPoint Energy	X	X	X	X	X
Houston Electric	X
CERC		X	X		X

The following table presents operating income (loss) for each ~~of our business segments~~reportable segment for ~~2015~~, ~~2014~~2018, 2017 and ~~2013~~.2016. Included in revenues by reportable segment below are intersegment ~~sales. We account~~sales, which are accounted for ~~intersegment sales~~ as if the sales were to third parties ~~that is,~~ 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 ~~Business~~Reportable Segment


	Year Ended December 31,							Year Ended December 31,
	2015		2014		2013			2018			2017			2016
	(in millions)							(in millions)
CenterPoint Energy
Electric Transmission & Distribution	$	607	$	595	$	607		$	623		$	636		$	653
Natural Gas Distribution	273		287		263			266			348			321
Energy Services	42		52		13			(47		)	126			21
Interstate Pipelines	—		—		72
Field Services	—		—		73
Other Operations	11		1		(18		)	(11		)	26			28
Total Consolidated Operating Income	$	933	$	935	$	1,010
Total CenterPoint Energy Consolidated Operating Income								$	831		$	1,136		$	1,023
Houston Electric
Electric Transmission & Distribution (1)								$	625		$	637		$	652
CERC
Natural Gas Distribution								$	266		$	348		$	321
Energy Services								(47		)	126			21
Other Operations								3			(7		)	(1		)
Total CERC Consolidated Operating Income								$	222		$	467		$	341


(1)	Excludes weather hedge gain (loss) of $(2) million, $(1) million and $1 million recorded on CenterPoint Energy. See Note 9(a) to the consolidated financial statements for more information on the weather hedge.

Electric Transmission & Distribution (CenterPoint Energy and Houston Electric)

The following ~~tables provide~~table provides summary data of ~~our~~the Electric Transmission & Distribution ~~business segment for~~ ~~2015~~, ~~2014~~ ~~and~~ ~~2013~~:reportable segment:


	Year Ended December 31,						Year Ended December 31,
	2015		2014		2013		2018		2017		2016
Revenues:	(in millions, except throughput and customer data)						(in millions, except throughput and customer data)
Electric transmission and distribution utility	$	2,364	$	2,279	$	2,063
Transition and system restoration bond companies	481		566		507
TDU							$	2,638	$	2,588	$	2,507
Bond Companies							594		409		553
Total revenues	2,845		2,845		2,570		3,232		2,997		3,060
Expenses:
Operation and maintenance, excluding transition and system restoration bond companies	1,300		1,251		1,045
Depreciation and amortization, excluding transition and system restoration bond companies	340		327		319
Operation and maintenance, excluding Bond Companies							1,444		1,397		1,330
Depreciation and amortization, excluding Bond Companies							386		395		384
Taxes other than income taxes	222		224		225		240		235		231
Transition and system restoration bond companies	376		448		374
Bond Companies							539		334		462
Total expenses	2,238		2,250		1,963		2,609		2,361		2,407
Operating Income	$	607	$	595	$	607	$	623	$	636	$	653
Operating Income:
Electric transmission and distribution operations	$	502	$	477	$	474
Transition and system restoration bond companies (1)	105		118		133
TDU							$	568	$	561	$	562
Bond Companies (1)							55		75		91
Total segment operating income	$	607	$	595	$	607	$	623	$	636	$	653
Throughput (in gigawatt-hours (GWh)):
Throughput (in GWh):
Residential	28,995		27,498		27,485		30,405		29,703		29,586
Total	84,191		81,839		79,985		90,409		88,636		86,829
Number of metered customers at end of period:
Residential	2,079,899		2,033,027		1,982,699		2,198,225		2,164,073		2,129,773
Total	2,348,517		2,299,247		2,244,289		2,485,370		2,444,299		2,403,340


(1)	Represents the amount necessary to pay interest on the ~~transition and system restoration bonds.~~Securitization Bonds.

~~2015~~2018 Compared to ~~2014.~~2017. ~~Our~~The Electric Transmission & Distribution ~~business~~reportable segment reported operating income of ~~$607~~$623 million for ~~2015,~~2018, consisting of ~~$502 million~~ ~~from our regulated electric transmission and distribution utility operations (TDU) and~~ ~~$105 million~~ ~~related to transition and system restoration bond companies (Bond Companies). For 2014, operating income totaled $595 million, consisting of $477~~$568 million from the TDU and ~~$118~~$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 ~~$25~~$7 million primarily due to the following key factors:

higher transmission-related revenues of ~~$81~~$37 million, ~~which were partially offset by increased~~exclusive of the TCJA, and lower transmission costs billed by transmission providers of ~~$47~~$32 million;

•customer growth of ~~$25~~$31 million from the addition of ~~nearly 50,000 new~~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 ~~$17~~$8 million, primarily due to a return to more normal ~~weather; and~~

•~~rate relief associated with distribution capital investments of $5 million.~~

~~These increases to operating income were partially offset by the following:~~

•~~lower equity return of $20 million, primarily related to true-up proceeds;~~

~~lower revenues from energy efficiency bonuses of $15 million, including a one-time energy efficiency remand bonus in 2014 of $8 million;~~

•~~higher depreciation of $13 million; and~~

•~~lower right-of-way revenues of $7 million.~~

~~2014 Compared to 2013.~~ Our Electric Transmission & Distribution business segment reported operating income of $595 million for 2014, consisting of $477 million from the TDU and $118 million related to Bond Companies. For 2013, operating income totaled $607 million, consisting of $474 million from the TDU and $133 million related to Bond Companies.

~~TDU operating income increased $3 million due to the following key factors:~~

•~~customer growth of $33 million from the addition of almost 55,000 new customers;~~

•~~higher equity return of $23 million, primarily related to true-up proceeds; and~~

~~higher energy efficiency performance bonus of $15 million.~~weather.

These increases to operating income were partially offset by the following:

increased ~~labor~~operation and ~~support services~~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 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.

2017 Compared to 2016. The Electric Transmission & Distribution reportable segment reported operating income of $636 million for 2017, consisting of $561 million from the TDU and $75 million related to the Bond Companies. For 2016, operating income totaled $653 million, consisting of $562 million from the TDU and $91 million related to the Bond Companies.

TDU operating income decreased $1 million primarily due to the following key factors:

lower equity return of $22 million, primarily related to the annual true-up of transition charges correcting for over-collections that occurred during the preceding 12 months;

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

~~increased contracts~~higher operation and maintenance expenses of $18 million, primarily due to higher labor and benefits costs of $10 million and corporate support services expenses of ~~$19~~$8 million;

lower ~~right-of-way revenues of $8 million;~~

~~increased depreciation of $8 million;~~

~~an adjustment to our claims liability reserve of $6 million;~~

~~decreased~~ usage of ~~$5 million, primarily due to milder weather;~~$15 million; and

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

These decreases to operating income were partially offset by the following:

rate increases of $47 million related to distribution capital investments;

•customer growth of $32 million from the addition of almost 41,000 customers; and

higher transmission-related revenues of $61 million, partially offset by transmission costs billed by transmission providers of ~~$168 million, which were largely offset by increased transmission-related revenues of $164~~$56 million.

Natural Gas Distribution (CenterPoint Energy and CERC)

The following table provides summary data of ~~our~~the Natural Gas Distribution ~~business segment for 2015, 2014 and 2013:~~reportable segment:


	Year Ended December 31,						Year Ended December 31,
	2015		2014		2013		2018		2017		2016
	(in millions, except throughput and customer data)						(in millions, except throughput and customer data)
Revenues	$	2,632	$	3,301	$	2,863	$	2,967	$	2,639	$	2,409
Expenses:
Natural gas	1,297		1,961		1,607		1,467		1,164		1,008
Operation and maintenance	697		700		667		803		722		696
Depreciation and amortization	222		201		185		277		260		242
Taxes other than income taxes	143		152		141		154		145		142
Total expenses	2,359		3,014		2,600		2,701		2,291		2,088
Operating Income	$	273	$	287	$	263	$	266	$	348	$	321
Throughput (in Bcf):
Residential	171		197		182		186		151		152
Commercial and industrial	262		270		265		285		261		259
Total Throughput	433		467		447		471		412		411
Number of customers at end of period:
Residential	3,149,845		3,124,542		3,090,966		3,246,277		3,213,140		3,183,538
Commercial and industrial	253,921		249,272		247,100		260,033		256,651		255,806
Total	3,403,766		3,373,814		3,338,066		3,506,310		3,469,791		3,439,344

~~2015~~2018 Compared to ~~2014.~~2017. ~~Our~~The Natural Gas Distribution ~~business~~reportable segment reported operating income of ~~$273~~$266 million for ~~2015~~2018 compared to ~~$287~~$348 million for ~~2014.~~2017.

Operating income decreased ~~$14~~$82 million primarily as a result of the following key factors:

~~decreased usage~~lower revenue of ~~$25~~$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 ~~warmer weather compared to~~ the ~~prior year, partially mitigated by weather hedges and weather normalization adjustments;~~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 ~~$22 million;~~$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

~~increase in~~higher other taxes of $2 ~~million.~~million, primarily due to higher property taxes.

These decreases were partially offset by:

rate increases of ~~$23 million;~~$46 million, primarily in the Texas, Minnesota and Arkansas jurisdictions, exclusive of the TCJA impact discussed above;

~~increased economic activity across our footprint~~an increase in non-volumetric revenues of $7$10 million; and

a $10 million ~~including~~increase associated with customer growth from the addition of ~~approximately 30,000 customers; and~~over 36,000 customers.

~~increased other revenue of $5 million.~~

~~Decreased~~Increased operation and maintenance expense related to energy efficiency programs of $4$10 million and ~~decreased~~increased other taxes expense related to ~~higher~~ gross receipt taxes of ~~$10 million were offset by a corresponding decrease in the related revenues.~~

~~2014 Compared to 2013.~~ ~~Our Natural Gas Distribution business segment reported operating income of $287 million for 2014 compared to $263 million for 2013.~~

~~Operating income increased $24 million as a result of the following key factors:~~

~~increased usage of $16 million as a result of colder weather compared to the prior year, partially mitigated by weather hedges and weather normalization adjustments;~~

~~rate increases of $37 million; and~~

~~increased economic activity across our footprint of $10 million, including the addition of approximately 36,000 customers.~~

~~These increases were partially offset by:~~

~~increased contractor expense of $10 million, including pipeline integrity work;~~

~~higher depreciation and amortization of $16 million;~~

~~increase in taxes of~~ $7 ~~million; and~~

~~increased other operating expenses of $6 million.~~

~~Increased expense related to energy efficiency programs of $8 million and increased expense related to higher gross receipt taxes of $4~~ million were offset by a corresponding increase in the related revenues.

2017 Compared to 2016. The Natural Gas Distribution reportable segment reported operating income of $348 million for 2017 compared to $321 million for 2016.

Operating income increased $27 million primarily as a result of the following key factors:

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

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

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

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

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

These increases were partially offset by:

higher operation and maintenance expenses of $18 million, primarily due to increased bad debt expenses of $7 million, increased contract services of $7 million and increased insurance costs of $3 million; and

increased depreciation and amortization expense, primarily due to ongoing additions to plant-in-service, and other taxes of $16 million.

Increased operation and maintenance expense related to energy efficiency programs of $13 million and decreased other taxes expense related to gross receipt taxes of $5 million were offset by a corresponding increase or decrease in the related revenues.

Energy Services (CenterPoint Energy and CERC)

The following table provides summary data of ~~our~~the Energy Services ~~business segment for 2015, 2014 and 2013:~~reportable segment:


	Year Ended December 31,							Year Ended December 31,
	2015		2014		2013			2018			2017		2016
	(in millions, except throughput and customer data)							(in millions, except throughput and customer data)
Revenues	$	1,957	$	3,179	$	2,401		$	4,521		$	4,049	$	2,099
Expenses:
Natural gas	1,867		3,073		2,336			4,453			3,816		2,011
Operation and maintenance	42		47		46			96			86		58
Depreciation and amortization	5		5		5			16			19		7
Taxes other than income taxes	1		2		1			3			2		2
Total expenses	1,915		3,127		2,388			4,568			3,923		2,078
Operating Income	$	42	$	52	$	13
Operating Income (Loss)								$	(47	)	$	126	$	21

Mark-to-market gain (loss)	$	4	$	29	$	(2	)
Timing impacts related to mark-to-market gain (loss) (1)								$	(110	)	$	79	$	(21	)

Throughput (in Bcf)	618		631		600			1,355			1,200		777

Number of customers at end of period ~~(1)~~(2)	18,099		17,964		17,510			30,000			31,000		30,000


(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 ~~9,700~~65,000, 72,000 and ~~8,800~~60,100 natural gas customers as of December 31, ~~2014~~2018, 2017 and ~~2013,~~2016, respectively, that are under residential and small commercial choice programs invoiced by their host utility.

~~2015~~2018 Compared to ~~2014.~~2017. ~~Our~~The Energy Services ~~business~~reportable segment reported an operating loss of $47 million for 2018 compared to operating income of ~~$42~~$126 million for ~~2015 compared to $52~~2017.

Operating income decreased $173 million ~~for 2014. The decrease in operating income~~as a result of ~~$10 million was due to~~ the following key factors:

a ~~$25~~$189 million decrease from mark-to-market accounting for derivatives associated with certain natural gas purchases and sales used to lock in economic ~~margins. In 2015, a $4~~margins; and

an $10 million ~~mark-to-market benefit was recorded as compared to a benefit of $29 million in 2014. Offsetting this decrease was a $5 million reduction~~increase in operation and maintenance expenses, attributable to increased technology expenses, higher contract and ~~a $4 million benefit~~services expense related to pipeline integrity testing, higher support services and legal expenses.

These decreases were partially offset by the following:

a ~~lower inventory write down in 2015. The remaining~~$22 million increase in ~~operating income was primarily~~margin due to ~~improved margins resulting~~increased opportunities to optimize natural gas supply costs through storage and transportation capacity, primarily in the first quarter of 2018, and incremental volumes from ~~reduced fixed costs.~~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.

~~2014~~2017 Compared to ~~2013.~~2016. ~~Our~~The Energy Services ~~business~~reportable segment reported operating income of ~~$52~~$126 million for ~~2014~~2017 compared to ~~$13~~$21 million for ~~2013.~~2016. The increase in operating income of ~~$39~~$105 million was primarily due to a ~~$31~~$100 million increase from mark-to-market accounting for derivatives associated with certain natural gas purchases and sales used to lock in economic margins. A ~~$29~~weather-driven spike in natural gas prices at the end of 2017 caused the accrual of an unusually high mark-to-market asset, expected to be substantially reversed in the first quarter of 2018 as natural gas prices normalize. Operating income in 2017

also included approximately $5 million ~~mark-to-market gain was incurred in 2014 compared~~of expenses related to ~~a charge~~the acquisition and integration of ~~$2 million in 2013.~~AEM. The remaining increase in operating income was primarily due to ~~improved margins resulting from weather-related optimization of existing gas transportation assets, reduced fixed costs and~~ increased throughput ~~and price volatility.~~

~~Interstate Pipelines~~related to the acquisition of AEM in 2017.

Substantially all of our Interstate Pipelines business segment was contributed to Enable on May 1, 2013. As a result, this segment did not report operating results for 2014 or 2015. Our equity method investment and related equity income in Enable are included in our Midstream Investments ~~segment.~~ (CenterPoint Energy)

The following table provides ~~summary data~~pre-tax equity income of ~~our Interstate Pipelines business segment for~~ ~~2013~~:the Midstream Investments reportable segment:

Year Ended
December 31, 2013 (1)
(in millions, except throughput data)
Revenues $ 186
Expenses:
Natural gas 35
Operation and maintenance 51
Depreciation and amortization 20
Taxes other than income taxes 8
Total expenses 114
Operating Income $ 72

Equity in earnings of unconsolidated affiliates $ 7

Transportation throughput (in Bcf) 482



	Year Ended December 31,
	2018		2017		2016
	(in millions)
Equity earnings from Enable, net	$	307	$	265	$	208

~~(1) Represents January 2013 through April 2013 results only.~~

~~Equity Earnings.~~ This business segment recorded equity income of $7 million for the year ended December 31, 2013 from its interest in Southeast Supply Header, LLC (SESH), a jointly-owned pipeline. Beginning May 1, 2013, equity earnings related to our interest in SESH and Enable are reported as components of equity income in our Midstream Investments segment.

~~Field Services~~

Substantially all of our Field Services business segment was contributed to Enable on May 1, 2013. As a result, this segment did not report operating results for 2014 or 2015. Our equity method investment and related equity income in Enable are included in our Midstream Investments segment. The following table provides summary data of our Field Services business segment for ~~2013~~:

Year Ended
December 31, 2013 (1)
(in millions, except throughput data)
Revenues $ 196
Expenses:
Natural gas 54
Operation and maintenance 45
Depreciation and amortization 20
Taxes other than income taxes 4
Total expenses 123
Operating Income $ 73

Gathering throughput (in Bcf) 252

~~(1) Represents January 2013 through April 2013 results only.~~

~~Midstream Investments~~

~~The following table summarizes the equity earnings (losses) of our Midstream Investments business segment for~~ ~~2015~~, ~~2014~~ ~~and 2013:~~

Year Ended December 31,
2015 (2) 2014 (3) 2013 (4)
(in millions)
Enable (1) $ (1,633 ) $ 303
$ 173
SESH —
5
8
Total $ (1,633 ) $ 308
$ 181


~~(1)~~	These amounts include our share of Enable’s impairment of goodwill and long-lived assets and the impairment of our equity method investment in Enable totaling $1,846 million during the year ended December 31, 2015. This impairment is offset by $213 million of earnings for the year ended December 31, 2015.


~~(2)~~	~~We contributed our remaining 0.1% interest in SESH to Enable on June 30, 2015.~~


~~(3)~~	On April 16, 2014, Enable completed its initial public offering and, as a result, our limited partner interest in Enable was reduced from approximately 58.3% to approximately 54.7%. On May 30, 2014, we contributed to Enable our 24.95% interest in SESH, which increased our limited partner interest in Enable from approximately 54.7% to approximately 55.4% and reduced our interest in SESH to 0.1%.


~~(4)~~	~~Represents our 58.3% limited partner interest in Enable and our 25.05% interest in SESH for the eight months ended December 31, 2013.~~

Other Operations (CenterPoint Energy and CERC)

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



	Year Ended December 31,
	2018			2017			2016
	(in millions)
Revenues	$	15		$	14		$	15
Expenses	26			(12		)	(13		)
Operating Income (Loss)	$	(11	)	$	26		$	28

~~The following table provides summary data for our~~2018 Compared to 2017. CenterPoint Energy’s Other Operations ~~business~~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.~~2015~~, ~~2014~~ ~~and~~ ~~2013~~:

Year Ended December 31,
2015 2014 2013
(in millions)
Revenues $ 14
$ 15
$ 14
Expenses 3
14
32
Operating Income (Loss) $ 11
$ 1
$ (18 )

~~2015~~2017 Compared to ~~2014.~~2016. ~~Our~~CenterPoint Enegy’s Other Operations ~~business~~reportable segment reported operating income of ~~$11~~$26 million for ~~2015~~2017 compared to $1$28 million for ~~2014. The increase in~~2016. Operating income decreased $2 million primarily due to increased operating ~~income of $10 million is primarily related to decreased administrative and benefits costs ($8 million),~~expenses, partially offset by decreased depreciation and ~~amortization ($1 million) and decreased property taxes ($1 million).~~amortization.

~~2014 Compared to 2013.~~ ~~Our~~The following table shows the operating income (loss) of CERC’s Other Operations business segment reported operating income of $1 million for 2014 compared to an operating loss of $18 million for 2013. The increase in operating income of $19 million is primarily related to the costs associated with the formation of Enable in 2013 ($13 million) and decreased benefits costs ($8 million), which were partially offset by higher property taxes ($2 million).reportable segment:



	Year Ended December 31,
	2018			2017			2016
	(in millions)
Revenues	$	1		$	—		$	1
Expenses	(2		)	7			2
Operating Income (Loss)	$	3		$	(7	)	$	(1	)

LIQUIDITY AND CAPITAL RESOURCES

Historical Cash Flows

The net cash provided by (used in) operating, investing and financing activities for ~~2015~~2018, ~~2014~~2017 and ~~2013~~2016 is as follows:


										Year Ended December 31,
	Year Ended December 31,									2018									2017									2016
	2015			2014			2013			CenterPoint Energy			Houston Electric			CERC			CenterPoint Energy			Houston Electric			CERC			CenterPoint Energy			Houston Electric			CERC
	(in millions)									(in millions)
Cash provided by (used in):
Operating activities	$	1,865		$	1,397		$	1,613		$	2,136		$	1,115		$	814		$	1,417		$	905		$	278		$	1,923		$	1,102		$	512
Investing activities	(1,387		)	(1,384		)	(1,300		)	(1,207		)	(911		)	(697		)	(1,257		)	(776		)	(346		)	(1,034		)	(951		)	42
Financing activities	(512		)	77			(751		)	3,053			(108		)	(104		)	(245		)	(236		)	79			(808		)	(69		)	(553		)

~~Cash Provided by Operating Activities~~

~~Net~~Operating Activities. The following items contributed to increased (decreased) net cash provided by operating ~~activities increased~~ activities:~~$468 million~~ in ~~2015~~ ~~compared to~~ ~~2014~~ ~~primarily due to decreased net tax payments ($237 million~~), increased cash related to a decrease in gas storage inventory ($113 million), increased cash provided by net accounts receivable/payable ($85 million), increased cash provided by fuel cost recovery (~~$84 million), decreased net margin deposits ($75 million), increased cash provided by net regulatory assets and liabilities ($41 million) and increased cash from non-trading derivatives ($27 million), which were partially offset by decreased distributions from equity method investments ($159 million).~~



	Year Ended December 31,
	2018 compared to 2017									2017 compared to 2016
	CenterPoint Energy			Houston Electric			CERC			CenterPoint Energy			Houston Electric			CERC
	(in millions)
Changes in net income after adjusting for non-cash items	$	(63	)	$	154		$	(243	)	$	141		$	(22	)	$	215
Changes in working capital	604			57			595			(545		)	(189		)	(474		)
Change in equity in earnings from Enable, net of distributions (1)	225			—			—			(57		)	—			—
Changes related to discontinued operations (2)	—			—			176			—			—			—
Higher pension contribution	(21		)	—			—			(39		)	—			—
Other	(26		)	(1		)	8			(6		)	14			25
	$	719		$	210		$	536		$	(506	)	$	(197	)	$	(234	)


(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.

Net cash provided by operating activities decreased $216 million in 2014 compared to 2013 primarily due to increased net tax payments ($157 million), decreased cash provided by fuel cost recovery ($149 million), increased net margin deposits ($95 million), decreased cash related to gas storage inventory ($69 million), decreased cash from non-trading derivatives ($38 million) and decreased cash provided by net regulatory assets and liabilities ($39 million), which was partially offset by increased distributions from equity method investments ($176 million) and increased cash provided by net accounts receivable/payable ($140 million).


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

~~Cash Used in~~ Investing ~~Activities~~

~~Net~~Activities.The following items contributed to (increased) decreased net cash used in investing activities increased $3 million in 2015 compared to 2014 primarily due to increased capital expenditures ($212 million), which were partially offset by a return of capital from unconsolidated affiliates ($148 million), increased proceeds from sale of marketable securities ($32 million) and decreased restricted cash ($19 million).activities:

Net cash used in investing activities increased $84 million in 2014 compared to 2013 primarily due to increased capital expenditures ($86 million), increased restricted cash ($24 million) and decreased proceeds from sale of marketable securities ($9 million), which were partially offset by decreased cash



	Year Ended December 31,
	2018 compared to 2017									2017 compared to 2016
	CenterPoint Energy			Houston Electric			CERC			CenterPoint Energy			Houston Electric			CERC
	(in millions)
Proceeds from the sale of marketable securities	$	398		$	—		$	—		$	(178	)	$	—		$	—
Acquisitions, net of cash acquired	132			—			132			(30		)	—			(30		)
Net change in capital expenditures	(225		)	(47		)	(120		)	(12		)	(13		)	4
Investment in Enable Series A Preferred Units	—			—			—			363			—			—
Net change in notes receivable from unconsolidated affiliates	—			(96		)	(114		)	(363		)	192			—
Change in distributions from Enable in excess of cumulative earnings	(267		)	—			—			—			—			—
Changes related to discontinued operations (1)	—			—			(250		)	—			—			(363		)
Other	12			8			1			(3		)	(4		)	1
	$	50		$	(135	)	$	(351	)	$	(223	)	$	175		$	(388	)


(1)	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 ~~Enable ($38 million).~~

~~Cash Provided by (Used in) Financing Activities~~

~~Net~~(increased) decreased net cash used in financing activities increased $589 million in 2015 compared to 2014 primarily due to decreased proceeds from long-term debt ($600 million), increased payments of long-term debt ($107 million), increased distributions to ZENS holders ($32 million), decreased short-term borrowings ($23 million), increased payments of common stock dividends ($18 million) and decreased proceeds from commercial paper ($11 million), which were partially offset by increased borrowings under our revolving credit facility ($200 million).activities:



	Year Ended December 31,
	2018 compared to 2017									2017 compared to 2016
	CenterPoint Energy			Houston Electric			CERC			CenterPoint Energy			Houston Electric			CERC
	(in millions)
Net changes in commercial paper outstanding	$	(1,892	)	$	—		$	(1,017	)	$	(120	)	$	—		$	(21	)
Increased proceeds from issuances of preferred stock	1,740			—			—			—			—			—
Increased proceeds from issuance of Common Stock	1,844			—			—			—			—			—
Net changes in long-term debt outstanding, excluding commercial paper	2,126			77			851			503			(123		)	73
Net changes in reacquired debt	5			—			5			17			—			(5		)
Net changes in debt issuance costs	(34		)	(1		)	(1		)	(4		)	3			(4		)
Net changes in short-term borrowings	(43		)	—			(43		)	9			—			9
Distributions to ZENS note holders	(398		)	—			—			178			—			—
Increased payment of Common Stock dividends	(38		)	—			—			(18		)	—			—
Increased payment of preferred stock dividends	(11		)	—			—			—			—			—
Net change in notes payable from affiliated companies	—			(119		)	(1,140		)	—			372			570
Contribution from parent	—			200			922			—			(374		)	(34		)
Dividend to parent	—			(29		)	241			—			(45		)	42
Other	(1		)	—			(1		)	(2		)	—			2
	$	3,298		$	128		$	(183	)	$	563		$	(167	)	$	632

Net cash provided by financing activities increased $828 million in 2014 compared to 2013 primarily due to decreased payments of long-term debt ($1,036 million) and increased proceeds from commercial paper ($296 million), which were partially offset by decreased proceeds from long-term debt ($450 million) and increased payments of common stock dividends ($53 million).

Future Sources and Uses of Cash

~~Our~~The liquidity and capital requirements of the Registrants are affected primarily by ~~our~~ results of operations, capital expenditures, debt service requirements, tax payments, working capital needs and various regulatory actions. ~~Our~~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 ~~2016~~2019 include the following:

~~capital expenditures of approximately $1.4 billion;~~



	CenterPoint Energy		Houston Electric		CERC
	(in millions)
Merger consideration for Vectren acquisition (1)	$	5,982	$	—	$	—
Estimated capital expenditures (2)	2,432		979		714
Change in control debt redemption (1)	759		—		—
Scheduled principal payments on Securitization Bonds	458		458		—
Minimum contributions to pension plans and other post-retirement plans	110		10		4
Maturing Vectren senior notes	60		—		—


(1)	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. In conjunction with the consummation of the Merger, $759 million of debt at Vectren was redeemed due to the change in control. For further discussion of the Merger, see Note 4 to the consolidated financial statements.

~~scheduled principal payments on transition and system restoration bonds of $391 million;~~


(2)	CenterPoint Energy’s estimated capital expenditures include estimated capital expenditures for Vectren and its subsidiaries as of the closing of the Merger.

~~investment in Enable’s Series A Preferred Units of $363 million;~~

~~maturing senior notes of $325 million;~~

~~acquisition of the retail commercial and industrial businesses of Continuum for $77.5 million plus working capital;and~~

~~dividend payments on CenterPoint Energy common stock and interest payments on debt.~~

WeThe Registrants expect that anticipated ~~2016~~2019 cash needs will be met with borrowings under ~~our~~their credit facilities, ~~proceeds from commercial paper,~~ proceeds from the issuance of long-term debt (including Houston Electric’s January 2019 issuance of $700 million aggregate principal

amount of general mortgage ~~bonds,~~bonds), 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. In addition, if CenterPoint Energy decides to sell Enable ~~and Enable’s redemption~~common units that it owns in the public equity markets or otherwise in 2019 (reducing the amount of ~~$363 million~~future distributions CenterPoint Energy receives from Enable to the extent of ~~notes owed to~~any such sales), any net proceeds received from such sales could provide a ~~wholly-owned subsidiary of CERC Corp.~~source for CenterPoint Energy’s remaining 2019 cash needs. 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.~~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 and any sales of CenterPoint Energy’s Enable common units may not, however, be available ~~to us~~ on acceptable terms.

The following table sets forth ~~our~~the Registrants’ actual capital expenditures by reportable segment for ~~2015~~2018 and estimates of ~~our~~the Registrants’ capital expenditures ~~for~~ currently ~~identified or~~ planned for projects for ~~2016~~2019 through ~~2020:~~2023:


	2015		2016		2017		2018		2019		2020		2018		2019		2020		2021		2022		2023
	(in millions)
CenterPoint Energy													(in millions)
Electric Transmission & Distribution	$	934	$	833	$	786	$	735	$	685	$	686	$	952	$	979	$	1,028	$	1,178	$	979	$	980
Natural Gas Distribution	601		485		470		435		430		430		638		673		678		691		694		711
Energy Services	5		5		26		—		1		—		20		40		16		15		39		13
Other Operations	35		39		33		28		25		26		110		71		39		33		34		35
Vectren and its subsidiaries (1)													—		669		740		867		1,056		896
Total	$	1,575	$	1,362	$	1,315	$	1,198	$	1,141	$	1,142	$	1,720	$	2,432	$	2,501	$	2,784	$	2,802	$	2,635
Houston Electric (2)													$	952	$	979	$	1,028	$	1,178	$	979	$	980
CERC
Natural Gas Distribution													$	638	$	673	$	678	$	691	$	694	$	711
Energy Services													20		40		16		15		39		13
Other Operations													—		1		—		—		—		—
Total													$	658	$	714	$	694	$	706	$	733	$	724

Our capital expenditures are expected to be used for investment in infrastructure for our electric transmission and distribution operations and our natural gas distribution operations. These capital expenditures are anticipated to maintain reliability and safety as well as expand our systems through value-added projects.


(1)	Vectren 2019 capital expenditures reflect capital expenditure estimates for the period February through December 2019 only.


(2)	Houston Electric consists of a single reportable segment, Electric Transmission & Distribution.

The following table sets forth estimates of ~~our~~the Registrants’ contractual obligations as of December 31, 2018, including payments due by ~~period:~~period but does not include any amounts for Vectren or its subsidiaries:


Contractual Obligations	Total		2016		2017-2018		2019-2020		2021 and thereafter		Total		2019		2020-2021		2022-2023		2024 and thereafter
	(in millions)										(in millions)
Transition and system restoration bond debt	$	2,674	$	391	$	845	$	689	$	749
CenterPoint Energy
Securitization Bonds											$	1,435	$	458	$	442	$	375	$	160
Other long-term debt (1)	6,648		325		1,150		1,135		4,038		7,798		—		1,495		1,510		4,793
Interest payments — transition and system restoration bond debt (2)	367		95		146		76		50
Interest payments — Securitization Bonds (2)											125		46		51		24		4
Interest payments — other long-term debt (2)	3,639		290		504		406		2,439		4,482		350		679		541		2,912
Short-term borrowings	40		40		—		—		—
Capital leases	3		3		—		—		—
Operating leases (3)	24		5		7		5		7		36		6		11		7		12
Benefit obligations (4)	—		—		—		—		—		—		—		—		—		—
Non-trading derivative liabilities	16		11		5		—		—		131		126		5		—		—
Other commodity commitments (5)	1,685		478		862		307		38
Commodity and other commitments (5)											3,058		454		773		385		1,446
Total contractual cash obligations (6)	$	15,096	$	1,638	$	3,519	$	2,618	$	7,321	$	17,065	$	1,440	$	3,456	$	2,842	$	9,327



Contractual Obligations	Total		2019		2020-2021		2022-2023		2024 and thereafter
	(in millions)
Houston Electric
Securitization Bonds	$	1,435	$	458	$	442	$	375	$	160
Other long-term debt (1)	3,281		—		402		500		2,379
Interest payments — Securitization Bonds (2)	125		46		51		24		4
Interest payments — other long-term debt (2)	2,150		132		255		226		1,537
Non-trading derivative liabilities	24		24		—		—		—
Operating leases (3)	1		1		—		—		—
Benefit obligations (4)	—		—		—		—		—
Total contractual cash obligations (6)	$	7,016	$	661	$	1,150	$	1,125	$	4,080
CERC
Long-term debt	$	2,371	$	—	$	593	$	510	$	1,268
Interest payments — long-term debt (1)	1,488		111		209		153		1,015
Operating leases (3)	32		5		9		7		11
Benefit obligations (4)	—		—		—		—		—
Non-trading derivative liabilities	107		102		5		—		—
Commodity and other commitments (5)	3,058		454		773		385		1,446
Total contractual cash obligations (6)	$	7,056	$	672	$	1,589	$	1,055	$	3,740

(1)

~~2.0% Zero-Premium Exchangeable Subordinated Notes due 2029 (ZENS)~~ZENS obligations are included in the ~~2021~~2024 and thereafter column at their contingent principal amount as of December 31, ~~2015~~2018 of ~~$705~~$93 million. These obligations are exchangeable for cash at any time at the option of the holders for 95% of the current value of the reference shares attributable to each ZENS ($~~805~~540 million as of December 31, ~~2015~~2018), as discussed in Note 1012 to ~~our~~the consolidated financial statements.

(2)

WeThe Registrants calculated estimated interest payments for long-term debt as follows: for fixed-rate debt and term debt, wethe Registrants calculated interest based on the applicable rates and payment dates; for variable-rate debt and/or non-term debt, wethe Registrants used interest rates in place as of December 31, ~~2015~~2018. WeThe 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 ~~14(c)~~16(c) to ~~our~~the consolidated financial statements.


(4)	~~In 2016, we are not required~~See Note 8(g) to ~~make~~the consolidated financial statements for information on the Registrants’ expected contributions to ~~our qualified~~ pension ~~plan. We expect to contribute approximately~~ ~~$8 million~~plans and ~~$16 million, respectively, to our non-qualified pension and~~other postretirement ~~benefits~~ plans in ~~2016.~~ 2019.


(5)	For a discussion of commodity and other ~~commodity~~ commitments, please read Note ~~14(a)~~16(a) to ~~our~~the consolidated financial statements.

(6)

This table does not include estimated future payments for expected future ~~asset retirement obligations.~~AROs. These payments are primarily estimated to be incurred after ~~2021. We record a separate liability for the fair value of these asset retirement obligations which totaled $195 million as of December 31, 2015.~~2024. See Note 3(c) to ~~our~~the consolidated financial ~~statements.~~statements for further information.

Off-Balance Sheet Arrangements

~~Prior~~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 distribution of our ownership in Reliant Resources, Inc. (RRI) to our shareholders, CERC had guaranteed certain contractual obligations of what became RRI’s trading subsidiary. When the companies separated, RRI agreed to secure CERC against obligations under the guarantees RRI had been unable to extinguish by the time of separation. Pursuant to such agreement, as amended in December 2007, RRI (now GenOn Energy, Inc. (GenOn)) agreed to provide to CERC cash or letters of credit as security against CERC’s obligations under its remaining guarantees for demand charges under certain gas transportation agreements if and to the extent changes in market conditions expose CERC to a risk of loss on those guarantees based on an annual calculation, with any required collateral to be posted each December. The undiscounted maximum potential payout of the demand charges under these transportation contracts, which will be in effect until 2018, was approximately ~~$27 million~~ ~~as of~~ ~~December 31, 2015~~. Based on market conditions in the fourth quarter of 2015 at the time the most recent annual calculation was made under the agreement, GenOn was not obligated to post any security. If GenOn should fail to perform the contractual obligations, CERC could have to honor its guarantee and, in such event, any collateral provided as security may be insufficient to satisfy CERC’s obligations.

CenterPoint Energy has provided guarantees (CenterPoint Midstream Guarantees) with respect to the performance of certain obligations of Enable under long-term gas gathering and treating agreements with an indirect, wholly-owned subsidiary of Encana Corporation (Encana) and an indirect, wholly-owned subsidiary of Royal Dutch Shell plc (Shell). Under the terms of the omnibus agreement entered into in connection with the closing of the formation of Enable, Enable and CenterPoint Energy have agreed to use commercially reasonable efforts and cooperate with each other to terminate the CenterPoint Midstream Guarantees and to release CenterPoint Energy from such guarantees by causing Enable or one of its subsidiaries to enter into substitute guarantees or to assume the CenterPoint Midstream Guarantees as applicable. The guarantee in favor of the indirect, wholly-owned subsidiary of Encana was released on August 24, 2015. As of December 31, 2015, CenterPoint Energy had guaranteed Enable’s obligations up to an aggregate amount of $50 million under the guarantee in favor of the indirect, wholly-owned subsidiary of Shell.

CERC Corp. has also provided a guarantee of collection of $1.1 billion of Enable’s senior notes due 2019 and 2024. This guarantee is subordinated to all senior debt of CERC Corp. and is subject to automatic release on May 1, 2016.

~~The fair value of these guarantees is not material. Other than the guarantees described above~~consolidated financial statements) and operating leases, wethe Registrants have no off-balance sheet arrangements.

Regulatory Matters

~~CenterPoint Houston~~

Brazos Valley Connection ~~Project.~~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. Houston Electric applied

for interim recovery of project costs incurred through July 31, 2018, which were not already included in rates in a filing with the PUCT in September 2018 and received approval for interim recovery in November 2018. Final approval by the PUCT of the project costs is expected to occur in Houston Electric’s next base rate case, which is anticipated to be filed in April 2019.

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

In ~~July 2013, CenterPoint~~April 2017, Houston ~~and other transmission service providers~~Electric submitted ~~analyses and transmission proposals~~a proposal to ERCOT ~~for an additional transmission path into the Houston region. In April 2014, ERCOT’s Board~~requesting its endorsement of ~~Directors voted to endorse~~ a ~~Houston region~~ transmission project in the greater Freeport, Texas area, which includes enhancements to two existing substations and ~~deemed its completion before June 2018 critical for reliability. The project will consist of (i)~~the construction of a new double-circuit 345 kilovolt (kV) line spanning approximately 130 miles, (ii) upgrades to three substations to accommodate new connections and additional capacity, and (iii) improvements to approximately 11 miles of an existing 345 kV ~~TH Wharton-Addicks transmission~~double-circuit line to ~~increase its rating. Also~~be located in ~~April 2014, ERCOT staff determined~~the counties of Brazoria, Matagorda and Wharton. 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 ~~CenterPoint Houston would be the designated transmission service provider~~included capital cost estimates for the ~~portion~~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 ~~between our Zenith substation and the Gibbons Creek substation owned by the Texas Municipal Power Agency, consisting of approximately 60–78 miles (depending~~will depend on the route approved by the Texas Utility Commission) of 345 kV transmission line, upgrades to the Limestone and Zenith substations and upgrades to 11 miles of the 345 kV TH Wharton-Addicks transmission line (this portion of the Houston region transmission project is referred to by CenterPoint Houston as the Brazos Valley Connection). Other transmission service providers were designated by ERCOT for the portion of the project from the Gibbons Creek Substation to the Limestone Substationthose factors as well as the upgrades to the Gibbons Creek Substation. In April 2015, CenterPoint Houston filed a CCN application with the Texas Utility Commission seeking approval to construct the Brazos Valley Connection. CenterPoint Houston proposed 32 alternative routes for the project in the application, including the Recommended Route that CenterPoint Houston identified in the application as best meeting the routing criteria used by the Texas Utility Commission in the route selection portion of CCN proceedings. The hearing on CenterPoint Houston’s CCN application was divided into two phases, a route-selection phase and a need phase. The route selection hearing was held on August 17 and 18, 2015. The hearing on the need for the line was held on September 2 and 3, 2015. On January 15, 2016, the Texas Utility Commission issued an order finding that the evidence presented by CenterPoint Houston, ERCOT, and others established the need for the project and approving a CCN for CenterPoint Houston to construct the Brazos Valley Connection using a modified version of the Recommended Route. A request for rehearing was filed with respect to the Texas Utility Commission’s route selection decision. That request for rehearing will automatically be deemed denied by operation of law on March 10, 2016, unless the Texas Utility Commission acts on the request before that date. No party filed a request for rehearing on the order’s need decision before the deadline expired and, therefore, that decision is final and not appealable. The Texas Utility Commission’s order provided an estimated range of approximately $270–$310 million for the capital costs for the Brazos Valley Connection. The actual cost will depend onother factors, including land acquisition costs, ~~material and~~ construction costs and ~~landowner elections permitted under~~ the ~~Texas Utility Commission’s order. CenterPoint Houston expects to complete construction~~ultimate route approved by the PUCT. On the request of the ~~Brazos Valley Connection by mid-2018.~~

~~In May 2014, several electric generators appealed~~PUCT, ERCOT intervened in the ~~ERCOT Board of Directors’ April 2014 approval~~proceeding and performed a re-evaluation of the cost-effectiveness of the proposed project. Based on that re-evaluation, ERCOT’s recommended transmission option for the project remains unchanged. Houston ~~region transmission project and the determination~~Electric anticipates that the ~~project was critical for reliability in~~PUCT will issue a final decision on the ~~Houston region to the Texas Utility Commission. That appeal was denied by the Texas Utility Commission in December 2014. In March 2015, the electric generators petitioned the Texas District Court~~certificate of ~~Travis County for judicial review of the Texas Utility Commission’s denial of their appeal. That case is currently pending before that court.~~

~~Transmission Cost of Service.~~ On November 21, 2014, CenterPoint Houston filed an application, as amended, with the Texas Utility Commission seeking an increase in annual transmission revenues based on an incremental increase in total rate base of

~~$113.2 million. CenterPoint Houston received approval from the Texas Utility Commission during the first quarter of 2015,~~convenience and ~~rates became effective February 25, 2015, resulting in an increase of $23.5 million in annual transmission revenues.~~

On June 26, 2015, CenterPoint Houston filed an application with the Texas Utility Commission for an interim update of its TCOS seeking an increase in annual transmission revenues based on an incremental increase of $87.6 million in total rate base. The Texas Utility Commission approved CenterPoint Houston’s application in the third quarter of 2015, and rates became effective August 17, 2015, resulting in an increase of $13.7 million in annual transmission revenues.

On October 1, 2015, CenterPoint Houston filed an application with the Texas Utility Commission for an interim update of its TCOS seeking an increase in annual transmission revenues based on an incremental increase of $107.6 million in total rate base. The Texas Utility Commission approved CenterPoint Houston’snecessity application in the fourth quarter of ~~2015, and rates became effective November 23, 2015, resulting in an increase of $16.8 million in annual transmission revenue.~~2019.

~~Distribution Cost Recovery Factor.~~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). The recently acquired Vectren entities are also routinely involved in rate change applications before regulatory authorities. However, disclosures related to rate change applications for Vectren entities during 2018 have not been included in the table below. The table below reflects significant applications pending or completed during 2018 and to date in 2019 for the Registrants.



Mechanism	Annual Increase (Decrease) (1) (in millions)	Filing Date	Effective Date	Approval Date	Additional Information
CenterPoint Energy and Houston Electric (PUCT)
TCOS	N/A	February 2018	April 2018	April 2018	Revised TCOS annual revenue application approved in November 2017 by a reduction of $41.6 million to recognize a decrease in the federal income tax rate, amortize certain EDIT balances and adjust rate base by EDIT attributable to new plant since the last rate case, all of which are related to the TCJA.
TCOS	$40.8	May 2018	July 2018	July 2018	Requested an increase of $285 million to rate base and reflects a $40.8 million annual increase in current revenues. Also reflects a one-time refund of $6.6 million in excess federal income tax collected from January to April 2018.
TCOS	2.4	September 2018	November 2018	November 2018	Requested an increase of $15.4 million to rate base and reflects a $2.4 million annual increase in current revenues.
EECRF	8.4	June 2018	March 2019	December 2018	The PUCT issued a final order in December 2018 approving recovery of 2019 EECRF of $39.5 million, including an $8.4 million performance bonus.
DCRF	30.9	April 2018	September 2018	August 2018	Unanimous settlement agreement approved by the PUCT in August 2018 results in incremental annual revenue of $30.9 million. It results in a $120.6 million annual revenue requirement effective September 1, 2018. The settlement agreement also reflects an approximately $39 million decrease resulting from the 21% federal income tax rate, a $20 million decrease to return to customers the reserve recorded recognizing this decrease in the federal income tax rate from January 25, 2018 through August 31, 2018 and a $19.2 million decrease related to the unprotected EDIT. Effective September 1, 2019, the reserve amount returned to customers ends. In December 2018, Houston Electric filed an updated DCRF tariff to adjust the interim DCRF rates to reflect the difference between the $20 million estimated tax-expense regulatory liability and the $23.4 million actual tax-expense regulatory liability recorded by Houston Electric.



Mechanism	Annual Increase (Decrease) (1) (in millions)	Filing Date	Effective Date	Approval Date	Additional Information
CenterPoint Energy and CERC - South Texas (Railroad Commission)
Rate Case	(1.0)	November 2017	May 2018	May 2018	Unanimous settlement agreement approved by the Railroad Commission in May 2018 that provides for a $1 million annual decrease in current revenues. The settlement agreement also reflects an approximately $2 million decrease in the federal income tax rate and amortization of certain EDIT balances and establishes a 9.8% ROE for future GRIP filings for the South Texas jurisdiction.
CenterPoint Energy and CERC - Beaumont/East Texas, Houston and Texas Coast (Railroad Commission)
GRIP	14.7	March 2018	July 2018	June 2018	Based on net change in invested capital of $70.0 million and reflects a $14.7 million annual increase in current revenues, net of an approximate $1.0 million decrease from the federal income tax rate reduction as a result of the TCJA.
Administrative 104.111	N/A	July 2018	September 2018	August 2018	Beaumont/East Texas, Houston and Texas Coast proposed to decrease base rates by $12.9 million to reflect the change in the federal income tax rate. In addition, Beaumont/East Texas proposed to decrease the GRIP charge to reflect the change in the federal income tax rate. The impact of deferred taxes is expected to be reflected in the next rate case.
CenterPoint Energy and CERC - Arkansas (APSC)
FRP	13.2	August 2018	October 2018	September 2018	Based on ROE of 9.5% as approved in the last rate case and reflects a $13.2 million annual increase in current revenues, excluding the effects of the TCJA. The annual increase is reduced from TCJA impacts by approximately $8.1 million, which include the effects of a lower federal income tax rate and amortization of EDIT balances.
CenterPoint Energy and CERC - Louisiana (LPSC)
RSP	6.1	December 2018	December 2018	February 2019	Based on ROE of 9.95% and the 21% federal income tax rate and reflects a $6.1 million annual increase in current revenues. Other impacts of the TCJA, which were calculated outside the band, reduced the annual increase by approximately $4 million. Interim rates were implemented in December 2018. Final rates were implemented February 2019 upon receipt of the LPSC’s final order. The LPSC also approved the refund of $5.6 million of other TCJA impacts over a three month period, beginning January 31, 2019.
CenterPoint Energy and CERC - Minnesota (MPUC)
Rate Case	3.9	August 2017	November 2018	July 2018	Includes a proposal to extend decoupling beyond current expiration date of June 2018. Interim rates reflecting an annual increase of $47.8 million were effective October 1, 2017. A unanimous settlement agreement was filed in March 2018, subject to MPUC approval. The settlement agreement increases base rates by $3.9 million, makes decoupling a permanent part of the tariff, incorporates the impact of the decrease in the federal income tax rate and amortization of EDIT balances (approximately $20 million) and establishes or continues tracker recovery mechanisms that account for approximately $13.3 million in the initial filing. The MPUC voted to approve the settlement and a formal order was issued on July 20, 2018. Final rates (and the refund of interim rates that exceed final rates) were implemented beginning November 1, 2018.
Decoupling	(13.8)	September 2018	September 2018	January 2019	Represents revenue over-recovery of $21.9 million recorded for and during the period July 1, 2017 through June 30, 2018 offset by the rate and prior period adjustments totaling $8.1 million recorded in 2018.
CIP	12.5	May 2018	September 2018	September 2018	Annual reconciliation filing for program year 2017 and includes performance bonus of $12.5 million which was recorded in September 2018.
CenterPoint Energy and CERC - Mississippi (MPSC)
RRA	3.2	May 2018	November 2018	November 2018	Based on authorized ROE of 9.144% and a capital structure of 50% debt and 50% equity and reflects a $3.2 million annual increase in revenues.
CenterPoint Energy and CERC - Oklahoma (OCC)
PBRC	5.4	March 2018	October 2018	October 2018	Based on ROE of 10% and reflects a $5.4 million annual increase in revenues. As a result of the final order, all EDIT was removed from the PBRC calculation. Protected EDIT amortization will begin to be refunded in April 2019 via one-time annual bill credits. Unprotected EDIT will be refunded over a five-year period via annual bill credits which began in October 2018.


(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

For the Registrants, federal income tax expense is included in the rates approved by state commissions and local municipalities and charged by those utilities to consumers. As the Registrants file general rate cases and other periodic rate adjustments, the impacts of the TCJA (including the lower tax rate and the calculation and amortization of EDIT), along with other increases and decreases in their revenue requirements, will be incorporated into the Registrants’ future rates as allowed by IRS rules. The effect of any potential return of tax savings resulting from the TCJA to consumers may differ depending on how each regulatory body requires the Registrants to return such savings. Regulatory commissions across most of the Registrants’ jurisdictions have issued accounting orders to track or record a regulatory liability for (1) the difference between revenues collected under existing rates and revenues that would have been collected had the existing rates been set using the recently approved federal income tax rates and (2) the balance of EDIT that now exists because of the reduction in federal income tax rates.

On ~~April 6, 2015, CenterPoint~~January 25, 2018, the PUCT issued an accounting order in Project No. 47945 directing electric utilities, including Houston ~~filed an application with~~Electric, to record as a regulatory liability (1) the ~~Texas Utility Commission~~difference between revenues collected under existing rates and revenues that would have been collected had the existing rates been set using the recently approved federal income tax rates and (2) the balance of EDIT that now exists because of the reduction in federal income tax rates. On February 13, 2018, Houston Electric and other likely parties to a future rate case announced a settlement that required Houston Electric to make (i) a TCOS filing by February 20, 2018 to reflect the change in the federal income tax rate for Houston Electric’s transmission rate base through July 31, 2017 (and such filing was timely submitted), (ii) a DCRF ~~interim~~filing in April 2018 to reflect the change in the federal income tax rate ~~adjustment to account~~ for ~~changes in certain distribution-invested capital since its 2010 rate case. The application requested (i) an increase in annual~~Houston Electric’s distribution ~~revenue of $16.7 million based on an increase in~~ rate base ~~from January 1, 2010~~ through December 31, ~~2014 of $417 million;~~2017 (and such filing was timely submitted) and ~~(ii) that rates become effective September 1, 2015.~~

The DCRF application must be filed between April 1 and April 8 of any given year. The application includes recovery of specific incremental distribution-related invested capital, including poles, transformers, conductors, meters and telecommunication equipment from the previous(iii) a full rate case filing by April 30, 2019. The settlement was presented to the ~~end of~~PUCT during its open meeting on February 15, 2018. In response to the ~~DCRF update period, less an adjustment for~~settlement, the related accumulated deferred income taxes. The application includes recovery of return on investment, depreciation expense, federal income tax, and other associated taxes less an adjustment for changes in customer count and weather normalized usage during the update period. The allocationPUCT did not proceed with a prior proposal to ~~customer classes is conducted~~require Houston Electric to file a rate case in the ~~same manner as current rates. Any authorized rate change~~summer of 2018. The PUCT also amended its prior accounting order to remove the requirement that utilities include carrying costs in the new regulatory liability. Additional information related to tax reform for Houston Electric is applied to all retail customers on an energy or demand charge basis, effective September 1, 2015, through a separate DCRF charge. Only four DCRF changes may be implemented between rate cases. The utility must file an earnings monitoring report (EMR) annually withdescribed in the ~~DCRF application. By law, a DCRF application will be denied if the EMR shows the utility is earning more than its authorized rate of return using 10-year weather normalized data.~~table above.

On ~~June 19, 2015,~~January 12, 2018, the APSC issued an ~~unopposed settlement agreement~~order in Docket No. 18-006-U opening an investigatory docket into the TCJA and directing utilities, including CERC, to record as a regulatory liability the current and deferred impacts of the TCJA. On July 26, 2018, the APSC issued an order in the investigatory docket requiring CERC to (1) include the reduction in tax expense due to the January 1, 2018 change in the tax rate from 35% to 21% in the utility’s FRP as a reduction to the revenue requirement; this reduction will be reflected in the utility’s historical year netting process in the 2019 FRP filing; (2) file and include all unprotected EDIT, including plant-related unprotected EDIT, in a separate rider within 30 days and refund the entire balance before December 31, 2019; (3) include protected EDIT in the FRP and amortize such amount using the ARAM method; and (4) adjust all other riders impacted by the TCJA changes and apply carrying charges calculated using the pre-tax cost of capital of 6.44% for the amounts related to the TCJA within 30 days of the July 26, 2018 order. On August 24, 2018 CERC filed Rider TCJA in Docket No. 18-050- TF. This rider returns the entire unprotected EDIT of approximately $19 million over five months from October 2018 through February 2019. The GMES Rider, which is not currently in effect, was revised to reflect the effects of the TCJA. No other riders were impacted. On September 21, 2018, the APSC approved Rider TCJA as filed, ~~providing for~~with an ~~increase in annual distribution revenue~~effective date of ~~$13.0 million, subject to final Texas Utility Commission approval. The Texas Utility Commission approved the settlement agreement on July 30, 2015. Rates became effective September~~October 1, ~~2015.~~

~~Energy Efficiency Cost Recovery Factor (EECRF).~~2018. On ~~June 1, 2015, CenterPoint Houston~~December 3, 2018, CERC filed ~~an application with the Texas Utility Commission for~~ an adjustment to ~~its EECRF~~Rider TCJA reflecting unprotected EDIT of approximately $17 million, as compared to ~~recover $37.7 million in 2016, including an incentive~~the originally estimated amount of ~~$6.6 million based on 2014 program performance. In October 2015,~~$19 million. This update reflects known amounts as a result of CNP’s 2017 corporate income tax filing. On December 21, 2018, the ~~Texas Utility Commission~~APSC approved the ~~application~~updated Rider TCJA effective through February 2019.

On October 5, 2018, the LPSC Staff filed its Final Report and Recommended Proposed Rule in Docket No. R-34754, which addresses the TCJA. The proposed rule recommends that CERC (1) adjust rates prospectively to ~~recover $37.6 million. The effective date~~reflect the new 21% federal corporate income tax rate; (2) refund to ratepayers 100% of federal corporate income taxes collected that are in excess of the new lower applicable tax rate ~~adjustment will be March 1, 2016.~~

~~CERC~~

~~Texas Coast Rate Case.~~ On March 27, 2015, NGD filed a Statement of Intent with each of the 49 cities and unincorporated areas within its Texas Coast service territory for a $6.8 million annual revenue increase. This increase was based on a rate base of $132.3 million and an ROE of 10.25%. On July 6, 2015, the parties agreed to a settlement providing for a $4.9 million annual increase to rates, an ROE of 10.0%, 54.5% equity and authorized overall rate of return of 8.23%. This settlement resolved six outstanding cases on appeal: one on remandplus carrying cost at the ~~Railroad Commission and five COSA appeals at the district court. The Railroad Commission unanimously approved the settlement on August 25, 2015. Rates were implemented in September 2015.~~

~~Houston, South Texas and Beaumont/East Texas GRIP~~. NGD’s Houston, South Texas and Beaumont/East Texas Divisions each submitted annual GRIP filings on March 31, 2015. For the Houston Division, NGD asked that its GRIP filing to recover costs related to $46.4 million in incremental capital expenditures that were incurred in 2014 be operationally suspended for one year so as to ensure that earnings are more consistent with those currently approved. For the South Texas Division, the revised filing requested recovery of costs related to $22.2 million in incremental capital expenditures that were incurred in 2014. The increase in revenue requirements for this filingutility’s WACC over a 12-month period is $4.0 million annually based on an authorized overall rate of return of 8.75%. For the Beaumont/East Texas Division, the GRIP filing requested recovery of costs related to $34.3 million in incremental capital expenditures that were incurred in 2014. The increase in revenue requirements for this filingor other period is $5.9 million annually based on an authorized overall rate of return of 8.51%. For the South Texas and Beaumont/East Texas Divisions, rates were implemented for certain customers in May 2015. For those areas in which the jurisdictional deadline was extended by regulatory action, the rates were implemented in July 2015 following approval by the Railroad Commission.

~~Oklahoma Performance Based Rate Change (PBRC).~~ ~~In March 2015, NGD made a PBRC filing for the 2014 calendar year proposing to increase revenues by $0.9 million. On November 4, 2015, the Oklahoma Corporation Commission approved the request.~~

~~Arkansas Energy Efficiency Cost Recovery (EECR).~~ On March 31, 2015, NGD made an EECR filing with the APSC to recover $5.9 million for the 2015 program year. The purpose of the EECR is to recover NGD’s estimated expenses and lost contributions to fixed cost for the energy efficiency programs approved by the ~~APSC~~LPSC; (3) accrue carrying charges on EDIT balances at the utility’s WACC until fully amortized, except to the extent ratepayers are receiving benefits of EDIT as a reduction to rate base; (4) amortize protected EDIT over ARAM and ~~administered either jointly~~implement through an outside- the-band reduction in rates attributable to the annual amortization; and (5) amortize unprotected EDIT over 24 months or individually by NGD, plus a utility incentive earned for 2014, with adjustments for any over- or under-recovery from the prior period. The impact to customer bills is expected to be a small reduction due to actual program costs being less than estimated and a colder than normal year causing more EECR revenues than anticipated. New rates went into effect in July 2015.

~~Arkansas Rate Case.~~ On August 17, 2015, NGD filed a Notice of Intent to File a general rate case with the APSC. The rate case was filed on November 10, 2015 seeking a $35.6 million increase in revenue requirement and a 10.3% ROE. A procedural schedule has been established with a hearing scheduled for July 12, 2016. A final determination by the APSC is expected in the third quarter of 2016.

~~Louisiana Rate Stabilization Plan (RSP).~~ NGD made its 2015 Louisiana RSP filings with the Louisiana Public Service Commission (LPSC) on October 1, 2015. The North Louisiana Rider RSP filing shows a revenue deficiency of $1.0 million, and the South Louisiana Rider RSP filing shows a revenue deficiency of $1.5 million. Both 2015 RSP filings utilized the capital structure and ROE factorsother period approved by the LPSC and implement through an outside-the-band reduction in rates or special tax rider. The LPSC Staff presented this proposed rule to the LPSC for vote at the October 26, 2018 Business & Executive Session. The interim RSP rates, protected EDIT impacts and the reduction of corporate income tax were implemented on ~~September 23, 2015 discussed below. NGD began billing~~December 26, 2018. On January 16, 2019, the LPSC approved the TCJA impacts implemented in December ~~2015 subject~~and a separate TCJA rider to return the unprotected EDIT and excess funds collected over a ~~refund.~~ ~~NGD made its 2014 Louisiana RSP filings with the LPSC~~three-month period, which began on October 1, 2014. The North Louisiana Rider RSP filing shows a revenue deficiency of $4.0 million, compared to the authorized ROE of 10.25%. The South Louisiana Rider RSP filing shows a revenue deficiency of $2.3 million, compared to the authorized ROE of 10.5%. NGD began billing the revised rates in December 2014, subject to refund. On November 19, 2014, NGD sought permission to amend the 2013 South Louisiana RSP filing to use a more representative capital structure and to adjust the filing’s equity banding mechanism. On December 2, 2014, NGD sought permission for similar amendments to the 2013 North Louisiana RSP filing. On September 3, 2015, Uncontested Stipulated Settlement Agreements (Stipulations) between NGD and the LPSC Staff were filedJanuary 31, 2019, as provided in the ~~2013 Louisiana RSP dockets recommending a capital structure of 48% debt and 52% equity and ROE of 9.95%. On September 23, 2015, the LPSC~~final order issued orders approving the Stipulations and ordered refunds of the 2013 RSP over-collections plus 5% annual interest. Refunds for the 2013 North and South Louisiana RSP filings in the amount of approximately $0.9 million and $0.6 million, respectively, became effective in September 2015. The 2014 and 2015 Louisiana RSP filings are still awaiting final approval from the LPSC.February 1, 2019.

On ~~February 20, 2015,~~November 6, 2018, within the ~~LPSC~~order approving the 2018 Mississippi RRA, the MPSC ruled that protected EDIT will be amortized over ARAM beginning with the 2019 RRA, unprotected EDIT will be amortized over a three-year period beginning December 1, 2018, and the refund due to the change in tax rate for 2018 billings prior to the 2018 RRA implementation will be a

component of the 2019 RRA filing for the 2018 calendar year.

FERC Revised Policy Statement and NOPR (CenterPoint Energy and CERC)

On March 15, 2018, the FERC addressed treatment of federal income tax allowances in FERC-regulated pipeline rates. The FERC issued ~~orders reducing~~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. The FERC issued the Revised Policy Statement in response to a remand from the U.S. Court of Appeals for the D.C. Circuit in United Airlines v. FERC. On July 18, 2018, the FERC issued an order denying requests for rehearing of its Revised Policy Statement because it is a non-binding policy and parties will have the opportunity to address the policy as applied in future cases. On September 14, 2018, MRT, filed a Petition for Review. That case remains undecided.

On March 15, 2018, the FERC also proposed, in a NOPR, the method by which it would apply the Revised Policy Statement to FERC-jurisdictional natural gas pipeline rates, ~~and requiring refunds of over-collections plus 5% interest based on disallowance of certain costs included~~as well as account for the corporate income tax rate reduction in the ~~2012 RSP filings. North Louisiana was~~TCJA. On July 18, 2018, the FERC issued a final rule requiring FERC-regulated natural gas pipelines that have cost-based rates to make a filing providing certain cost and revenue information and then either propose to reduce or support current cost-based rates, or take no further action. The final rule is currently subject to requests for rehearing. On January 16, 2019, the FERC used this filing as the basis to open an investigation into the rates of Northern Natural Gas Company. CERC is a shipper on Northern Natural Gas Company’s pipeline system.

EGT, made its required filing on October 11, 2018, in which it asserted that no rate reduction is warranted. That filing remains subject to FERC review. MRT is not required to ~~adjust~~make such a filing as it is engaged in an ongoing rate case. As part of that rate case, FERC ordered the filings to conform to its ~~2012 RSP increase from $36,400~~tax policy. That order is currently subject to ~~$2,600. South Louisiana’s 2012 RSP was further reduced by $0.1 million. New~~requests for rehearing. SESH, in which Enable owns a 50% interest, made its required filing in November 2018 and a limited rate reduction filing. With regard to FERC-jurisdictional rates ~~went into effect~~ on ~~February 23, 2015.~~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. At this time, we cannot predict the outcome of the final rule on Enable, but it could continue to adversely impact the rates Enable is permitted to charge its customers.

~~Mississippi Rate Regulation Adjustment (RRA)~~. On May 1, 2015, NGD filed for a $2.5 million RRA with an adjusted ROE of 9.534% with the Mississippi Public Service Commission (MPSC). Additional filings were made under the Supplemental Growth Rider (SGR) of approximately $0.1 million with an ROE of 12% and the EECR rider of approximately $0.6 million. The MPSC approved the EECR and new rates were implemented on September 2, 2015. NGD and the Mississippi Commission Staff filed a Stipulation on December 1, 2015 in the RRA, which was approved by the MPSC on December 3, 2015. The stipulated revenue adjustment is $1.9 million with an ROE of 9.534%. The SGR was approved, as filed, on December 3, 2015. New rates for the RRA and the SGR were implemented in December of 2015.

~~Minnesota Conservation Cost Recovery Adjustment (CCRA) and CIP~~. On May 1, 2015, NGD filed applications with the MPUC for a CCRA and a Demand-Side Management Financial Incentive. NGD sought approval for a $2.3 million balance in its CIP Tracker, an $11.6 million financial incentive based on 2014 program performance, and an updated CCRA, to be effective on January 1, 2016. On August 11, 2015, the MPUC issued its order approving these requests.

~~Minnesota Rate Case.~~ In August 2015, NGD filed a general rate case with the MPUC requesting an annual increase of $54.1 million. On September 10, 2015, the MPUC approved an interim increase of $47.8 million in revenues effective October 2, 2015, subject to a refund. The MPUC is expected to issue a final decision in mid-2016 with final rates effective by the end of 2016.

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 $4.5 billion as of December 31, 2018. As of February 12, ~~2016, we~~2019, the Registrants had the following revolving credit facilities and utilization of such facilities:

Execution Date Company
Size of
Facility

Amount
Utilized at
February 12, 2016 (1)
Termination Date
(in millions)
September 9, 2011 CenterPoint Energy $ 1,200
$ 826
⁽²⁾
September 9, 2019
September 9, 2011 CenterPoint Houston 300
204
⁽³⁾
September 9, 2019
September 9, 2011 CERC Corp. 600
18
⁽⁴⁾
September 9, 2019



			Amount Utilized as of February 12, 2019
Registrant/Subsidiary	Size of Facility		Loans		Letters of Credit		Commercial Paper		Weighted Average Interest Rate	Termination Date
	(in millions, except weighted average interest rate)
CenterPoint Energy (1)	$	3,300	$	—	$	6	$	2,592	2.88%	March 2022
VUHI (2)	400		—		—		190		2.73%	July 2022
Vectren Capital Corp. (2)	200		37		—		—		3.63%	July 2022
Total CenterPoint Energy	3,900		37		6		2,782
Houston Electric	300		—		4		—		—	March 2022
CERC (3)	900		—		1		—		—	March 2022
Total	$	5,100	$	37	$	11	$	2,782

(1)

~~Based on~~Pursuant to the ~~consolidated debt to capitalization covenant~~amendment entered into in ~~our~~May 2018, the aggregate commitments under the CenterPoint Energy revolving credit facility ~~and~~increased to $3.3 billion on October 5, 2018 due to the ~~revolving credit facility~~satisfaction of ~~each~~certain conditions, including the termination of ~~CenterPoint Houston and CERC Corp., we would have been permitted~~the Bridge Facility. For further information, see Note 4 to ~~utilize~~ the ~~full capacity of such revolving credit facilities, which aggregated $2.1 billion at December 31, 2015.~~consolidated financial statements.


(2)	~~Represents~~Vectren’s outstanding ~~commercial paper~~short-term and long-term debt on the closing date of ~~$820 million and outstanding letters~~the Merger became debt of ~~credit of $6 million.~~CenterPoint Energy.


(3)	~~Represents outstanding letters of credit of $4 million and outstanding bank loans of $200 million.~~Issued by CERC Corp.


~~(4)~~	~~Represents outstanding commercial paper of $16 million and outstanding letters of credit of $2 million.~~

Our $1.2 billion revolving credit facility can be drawn at the London Interbank Offered Rate (LIBOR) plus 1.25% based on our current credit ratings. The revolving credit facility contains a financial covenant which limits our consolidated debt (excluding transition and system restoration bonds) to an amount not to exceed 65% of our consolidated capitalization. As of December 31, 2015, our debt (excluding transition and system restoration bonds) to capital ratio, as defined in our credit facility agreement, was 55.1%. The financial covenant limit will temporarily increase from 65% to 70% if CenterPoint Houston experiences damage from a natural disaster in its service territory and we certify to the administrative agent that CenterPoint Houston has incurred system restoration costs reasonably likely to exceed $100 million in a consecutive twelve-month period, all or part of which CenterPoint Houston intends to seek to recover through securitization financing. Such temporary increase in the financial covenant would be in effect from the date we deliver our certification until the earliest to occur of (i) the completion of the securitization financing, (ii) the first anniversary of our certification or (iii) the revocation of such certification.

CenterPoint Houston’s $300 million revolving credit facility can be drawn at LIBOR plus 1.125% based on CenterPoint Houston’s current credit ratings. The revolving credit facility contains a financial covenant which limits CenterPoint Houston’s consolidated debt (excluding transition and system restoration bonds) to an amount not to exceed 65% of CenterPoint Houston’s consolidated capitalization. As of December 31, 2015, CenterPoint Houston’s debt (excluding transition and system restoration bonds) to capital ratio, as defined in its credit facility agreement, was 51.7%.

CERC Corp.’s $600 million revolving credit facility can be drawn at LIBOR plus 1.5% based on CERC Corp.’s current credit ratings. The revolving credit facility contains a financial covenant which limits CERC’s consolidated debt to an amount not to exceed 65% of CERC’s consolidated capitalization. As of December 31, 2015, CERC’s debt to capital ratio, as defined in its credit facility agreement, was 33.9%.

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

Our $1.2 billion revolving credit facility backstops our $1.0 billion commercial paper program. As of December 31, 2015, we had $716 million of outstanding commercial paper with a weighted average interest rate of 0.79%. CERC Corp.’s $600 million

revolving credit facility backstops its $600 million commercial paper program. As of December 31, 2015, CERC Corp. had $219 million of outstanding commercial paper with a weighted average interest rate of 0.81%.Long-term Debt

~~In November 2015, we retired $740 million~~For detailed information about the Registrants’ debt issuances in 2018 and to date in 2019, see Note 14 to the consolidated financial statements.

Vectren Debt

As a result of ~~tax-exempt municipal bonds that had been held~~the Merger, Vectren’s outstanding short-term and long-term debt on the closing date of the Merger became debt of CenterPoint Energy, which included debt of Vectren and its subsidiaries with maturities ranging from 2019 to 2055 and containing customary covenants for ~~remarketing.~~investment grade debt.

Securities Registered with the SEC

~~CenterPoint Energy, CenterPoint Houston and CERC Corp. have~~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 ~~CenterPoint Houston’s~~Houston Electric’s general mortgage bonds, CERC Corp.’s senior debt securities and CenterPoint Energy’s senior debt securities and junior subordinated debt securities and an indeterminate number of ~~CenterPoint Energy’s~~ shares of ~~common stock,~~Common Stock, shares of preferred stock, depositary shares, as well as stock purchase contracts and equity units. The joint shelf registration statement will expire on January 31, 2020. For information related to the Registrants’ debt and equity security issuances in 2018 and to date in 2019, see Notes 13 and 14 to the consolidated financial statements.

Temporary Investments

As of February 12, ~~2016, we~~2019, the Registrants had no temporary investments.

Money Pool

~~We have~~The Registrants participate in a money pool through which ~~the holding company~~they and ~~participating~~certain of their subsidiaries can borrow or invest on a short-term basis. CNP Midstream cannot borrow from the money pool but can invest in it. 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 ~~our~~CenterPoint Energy’s revolving credit facility or the sale of ~~our~~CenterPoint Energy’s commercial paper. The money pool may not provide sufficient funds to meet the Registrants’ cash needs.

The table below summarizes money pool activity by participant as of February 12, 2019:



	Weighted Average Interest Rate	Houston Electric		CERC		CNP Midstream
		(in millions)
Money pool investments	2.92%	$	485	$	27	$	293

Impact on Liquidity of a Downgrade in Credit Ratings

The interest on borrowings under ~~our~~the Registrants’ credit facilities is based on ~~our~~their credit ~~rating.~~ratings. On January 28, 2019, in anticipation of the closing of the Merger, Moody’s downgraded CenterPoint Energy’s senior unsecured debt rating to Baa2 from Baa1 and changed the rating outlook for CenterPoint Energy to stable from negative. On February 1, 2019, as a result of the closing of the Merger, S&P lowered its issuer credit rating on CenterPoint Energy’s senior unsecured debt to BBB from BBB+. S&P also lowered its issuer credit ratings on Houston Electric and CERC Corp. to BBB+ from A- in each case, affirmed the A credit rating on Houston Electric’s senior secured debt and lowered the credit rating on CERC’s senior unsecured debt to BBB+ from A-. Additionally, S&P removed the issuer credit ratings for each Registrant from CreditWatch and changed the rating outlooks to stable. As of February 12, ~~2016,~~2019, Moody’s, ~~Investors Service, Inc. (Moody’s), Standard & Poor’s Ratings Services (S&P), a division of The McGraw-Hill Companies,~~S&P and Fitch ~~Inc. (Fitch)~~ had assigned the following credit ratings to senior debt of ~~CenterPoint Energy and certain subsidiaries:~~the Registrants:

Moody’s

S&P

Fitch

~~Company/~~Registrant/Instrument

Rating

Outlook (1)

Rating

Outlook (2)

Rating

Outlook (3)

CenterPoint Energy Senior

Unsecured Debt

~~Baa1~~Baa2

Stable

~~BBB+~~BBB

~~Negative~~Stable

BBB

Stable

~~CenterPoint~~ Houston Electric Senior

Secured Debt

Stable

~~Negative~~Stable

AA+

Stable

CERC ~~Corp.~~ Senior Unsecured

Debt(4)

~~Baa2~~Baa1

Positive

BBB+

Stable

A-

~~Negative~~

~~BBB~~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 ~~rating~~ outlook assesses the potential direction of a long-term credit rating over the intermediate to longer term.


(3)	A Fitch rating outlook indicates the direction a rating is likely to move over a one- to two-year period.


(4)	Issued by CERC Corp.

As of February 12, 2019, Moody’s and S&P had assigned the following credit ratings to CenterPoint Energy’s Vectren entities:



	Moody’s		S&P
Company/Instrument	Rating	Outlook (1)	Rating	Outlook (2)
Vectren Corp. Issuer Rating	n/a	n/a	BBB+	Stable
VUHI Senior Unsecured Debt	A2	Negative	BBB+	Stable
Indiana Gas Senior Unsecured Debt	A2	Negative	BBB+	Stable
SIGECO Senior Secured Debt	Aa3	Negative	A	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.

The Registrants cannot assure that the ratings set forth above will remain in effect for any given period of time or that one or more of these ratings will not be lowered or withdrawn entirely by a rating agency. WeThe Registrants note that these credit ratings are included for informational purposes and are not recommendations to buy, sell or hold ~~our~~the Registrants’ securities and may be revised or withdrawn at any time by the rating agency. Each rating should be evaluated independently of any other rating. Any future reduction or withdrawal of one or more of ~~our~~the Registrants’ credit ratings could have a material adverse impact on ~~our~~the Registrants’ ability to obtain short- and long-term financing, the cost of such financings and the execution of ~~our~~the Registrants’ commercial strategies.

A decline in credit ratings could increase borrowing costs and other fees under ~~our $1.2 billion~~the Registrants’ revolving credit facilities. As a result of the January 28, 2019 and February 1, 2019 credit ratings downgrade of CenterPoint Energy at Moody’s and S&P, respectively, commitment fees on undrawn balances under CenterPoint Energy’s revolving credit facility ~~CenterPoint Houston’s $300~~of $3.3 billion as of December 31, 2018 are expected to increase by approximately $2 million annually. Additionally, as a result of the February 1, 2019 credit rating downgrades of CERC at S&P, commitment fees on undrawn balances under CERC’s revolving credit facility ~~and CERC Corp.’s $600~~of $0.9 billion as of December 31, 2018 are expected to increase by less than $1 million ~~revolving credit facility.~~annually. If ~~our~~the Registrants’ credit ratings ~~or those of CenterPoint Houston or CERC Corp.~~ had been further downgraded one notch by each of ~~the three principal credit rating agencies~~Moody’s and S&P from the ratings that existed ~~at December 31, 2015,~~immediately after February 1, 2019, the impact on the borrowing costs under the ~~three~~respective revolving credit facilities would not 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 our ability to complete capital market transactions and to access the commercial paper market.

~~Additionally, a decline in credit ratings could increase cash collateral requirements and reduce earnings of our Natural Gas Distribution and Energy Services Business Segments.~~material.

CERC Corp. and its subsidiaries purchase natural gas from one of their suppliers under supply agreements that contain an aggregate credit threshold of $140 million based on CERC Corp.’s S&P senior unsecured long-term debt rating of A-. Under these agreements, CERC may need to provide collateral if the aggregate threshold is exceeded or if the credit threshold is decreased due to a credit rating downgrade.

CES, a wholly-owned subsidiary of CERC Corp. operating in ~~our~~the Energy Services ~~business~~reportable segment, provides natural gas sales and services primarily to commercial and industrial customers and electric and natural gas utilities throughout the ~~central and eastern~~ United

States. ~~In order to~~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, ~~2015,~~2018, the amount posted by CES as collateral aggregated approximately ~~$87~~$36 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. WeCenterPoint Energy and CERC estimate that as of December 31, ~~2015~~,2018, unsecured credit limits extended to CES by counterparties aggregated ~~$308~~$268 million, and ~~$3 million~~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 Corp. might need to provide cash or other collateral of as much as ~~$152~~$186 million as of December 31, ~~2015.~~2018. The amount of collateral will depend on seasonal variations in transportation levels.

~~In September 1999, we issued~~ ZENS having an original principal amount of $1.0 billion of which $828 million remains outstanding at December 31, 2015. Each ZENS note was originally exchangeable at the holder’s option at any time for an amount of cash equal to 95% of the market value of the reference shares of TW Common attributable to such note. The number and identity of the reference shares attributable to each ZENS note are adjusted for certain corporate events. Prior to the closing of the merger discussed below, the reference shares for each ZENS note consisted of 0.5 share of TW Common, 0.125505 share of TWC Common, 0.045455 share of AOL Common and 0.0625 share of Time Common.

On May 26, 2015, Verizon initiated a tender offer to purchase all outstanding shares of AOL Common for $50 per share, in which we tendered all of our shares of AOL Common for $32 million. Verizon acquired the remaining eligible shares through a merger, which closed on June 23, 2015. In accordance with the terms of the ZENS, we remitted $32 millionSecurities Related to ZENS holders in July 2015, which reduced contingent principal. As a result, we recorded a reduction in the indexed debt securities derivative liability of $18 million, a reduction in the indexed debt balance of $7 million and a loss of $7 million, which is included in Gain (loss) on indexed debt securities on the Statements of Consolidated Income. As of December 31, 2015, the reference shares for each ZENS note consisted of 0.5 share of TW Common, 0.125505 share of TWC Common and 0.0625 share of Time Common, and the contingent principal balance was $705 million.

On May 26, 2015, Charter Communications, Inc. (Charter) announced that it had entered into a definitive merger agreement with TWC. On September 21, 2015, Charter shareholders approved the announced transaction with TWC. Pursuant to the merger agreement, upon closing of the merger, TWC Common shares would be exchanged for cash and Charter stock and as a result, reference shares would consist of Charter stock, TW Common and Time Common. The merger is expected to close by June of 2016.(CenterPoint Energy)

If ~~our~~CenterPoint Energy’s creditworthiness were to drop such that ZENS ~~note~~ holders thought ~~our~~its liquidity was adversely affected or the market for the ZENS ~~notes~~ were to become illiquid, some ZENS ~~note~~ holders might decide to exchange their ZENS ~~notes~~ for cash. Funds for the payment of cash upon exchange could be obtained from the sale of the shares of ~~TW Common, TWC Common and Time Common~~ZENS-Related Securities that ~~we own~~CenterPoint Energy owns or from other sources. ~~We own~~CenterPoint Energy owns shares of ~~TW Common, TWC Common and Time Common~~ZENS-Related Securities equal to approximately 100% of the reference shares used to calculate ~~our~~its obligation to the holders of the ZENS. ZENS ~~notes. ZENS note~~ exchanges result in a cash outflow because tax deferrals related to the ZENS ~~notes~~ and ~~TW Common, TWC Common and Time Common~~ shares of ZENS-Related Securities would typically cease when ZENS ~~notes~~ are exchanged or otherwise retired and ~~TW Common, TWC Common and Time Common~~ shares of ZENS-Related Securities are sold. The ultimate tax liability related to the ZENS ~~notes~~ 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~~

~~notes.~~ZENS. If all ZENS ~~notes~~ had been exchanged for cash on December 31, ~~2015,~~2018, deferred taxes of approximately ~~$450~~$438 million would have been payable in ~~2015.~~2018. If all the ~~TW Common, TWC Common and Time Common~~shares of ZENS-Related Securities had been sold on December 31, ~~2015,~~2018, capital gains taxes of approximately ~~$236~~$90 million would have been payable in ~~2015.~~2018 based on 2018 tax rates in effect. For additional information about ZENS, see Note 12 to the consolidated financial statements.

Cross Defaults

Under ~~our~~CenterPoint Energy’s revolving credit facility, 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 ~~$75~~$125 million by usit or any of ~~our~~its significant subsidiaries will cause a default. A default by CenterPoint Energy would not trigger a default under ~~our~~its subsidiaries’ debt instruments or revolving credit facilities.

Possible Acquisitions, Divestitures and Joint Ventures

From time to time, wethe Registrants consider the acquisition or the disposition of assets or businesses or possible joint ventures, strategic initiatives or other joint ownership arrangements with respect to assets or businesses. Any determination to take action in this regard will be based on market conditions and opportunities existing at the time, and accordingly, the timing, size or success of any efforts and the associated potential capital commitments are unpredictable. WeThe Registrants may seek to fund all or part of any such efforts with proceeds from debt and/or equity issuances. Debt or equity financing may not, however, be available to usthe Registrants at that time due to a variety of events, including, among others, maintenance of ~~our~~their credit ratings, industry conditions, general economic conditions, market conditions and market perceptions.

~~On February 1, 2016, we announced that we are evaluating strategic alternatives for our investment~~Additionally, CenterPoint Energy may also reduce its ownership in Enable ~~including a sale~~over time through sales in the public equity markets, or ~~spin-off qualifying under Section 355~~otherwise, of the ~~U.S. Internal Revenue Code,~~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 ~~exploring~~terms of any such sale. Any sales of Enable common units CenterPoint Energy owns could have an adverse impact on the ~~use~~price of ~~the real estate investment trust business model~~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 ~~part~~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 its ability to meet its payment obligations and pay dividends on its Common

Stock. Further, any sales of ~~our utility businesses.~~Enable common units would result in a significant amount of taxes due. There can be no assurances that ~~this evaluation~~any sale of Enable common units in the public equity markets or otherwise will ~~result~~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 ~~specific action, and we do~~public offering, a significant underwriting discount. CenterPoint Energy may not ~~intend to disclose further developments on these initiatives unless and until our Board~~realize any or all of ~~Directors approves a specific action~~the anticipated strategic, financial, operational or ~~as otherwise required.~~other benefits from any completed sale or reduction in its investment in Enable.

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 ~~December 31, 2015, certain~~tax, in CERC’s Statements of Consolidated Income for the ~~entities contributed~~periods presented. For further information, see Note 11 to ~~Enable by CERC Corp. were obligated on approximately $363 million of indebtedness owed to a wholly-owned subsidiary of CERC Corp.~~the consolidated financial statements.

~~On January 28, 2016, we entered into a purchase agreement with~~CenterPoint Energy receives quarterly cash distributions from Enable ~~pursuant to which we agreed to purchase in a Private Placement an aggregate of 14,520,000 10%~~on its common units and Enable Series A Preferred ~~Units for a cash purchase price of $25.00 per Series~~Units. A Preferred Unit. The Private Placement closed on February 18, 2016. In connection with the Private Placement, Enable redeemed approximately $363 million of notes scheduled to mature in 2017 payable to a wholly-owned subsidiary of CERC Corp. We used the proceeds from this redemption for our investmentreduction in the ~~Series A Preferred Units.~~

cash distributions CenterPoint Energy receives from Enable ~~is expected to pay a minimum quarterly distribution of $0.2875 per unit on its outstanding units~~could significantly impact CenterPoint Energy’s liquidity. For additional information about cash distributions from Enable, see Notes 11 and 22 to the extent it has sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to its general partner and its affiliates (referred to as “available cash”) within 45 days after the end of each quarter. On January 22, 2016, Enable declared a quarterly cash distribution of $0.318 per unit on all of its outstanding common and subordinated units for the quarter ended December 31, 2015. Accordingly, CERC Corp. expects to receive a cash distribution of approximately $74 million from Enable in the first quarter of 2016 to be made with respect to CERC Corp.’s limited partner interest in Enable for the fourth quarter of 2015.

We recognized a loss of $1,633 million from our investment in Enable for the year ended December 31, 2015. This loss included impairment charges totaling $1,846 million composed of the impairment of our investment in Enable of $1,225 million and our share, $621 million, of impairment charges Enable recorded for goodwill and long-lived assets. For further discussion of the impairment, see Note 9 to our consolidated financial statements.

~~Dodd-Frank Swaps Regulation~~Hedging of Interest Expense for Future Debt Issuances

~~We use derivative instruments such as physical~~From time to time, the Registrants may enter into forward ~~contracts, swaps~~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 ~~options~~CERC)

CenterPoint Energy and CERC have historically entered into partial weather hedges for certain NGD jurisdictions and electric operations’ service territory to mitigate the impact of ~~changes in commodity prices~~fluctuations from normal weather. CenterPoint Energy and CERC remain exposed to some weather on our operating results and cash flows. Following enactment of the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank) in July 2010, the Commodity Futures Trading Commission (CFTC) has promulgated regulations to implement Dodd-Frank’s changes to the Commodity Exchange Act, including the definition of commodity-based swaps subject to those regulations. The CFTC regulations are intended to implement new reporting and record keeping requirements related to their swap transactions and a mandatory clearing and exchange-execution regime for various types, categories or classes of swaps, subject to certain exemptions, including the trade-option and end-user exemptions. Although we anticipate that most, if not all, of our swap transactions should qualify for an exemption to the clearing and exchange-execution requirements, we will still be subject to record keeping and reporting requirements. Other changes to the Commodity Exchange Act maderisk as a result of ~~Dodd-Frank and~~ the ~~CFTC’s implementing regulations could increase~~partial hedges. For more information about weather hedges, see Note 9(a) to the ~~cost of entering into new swaps.~~

~~Weather Hedge~~

We have weather normalization or other rate mechanisms that mitigate the impact of weather on NGD in Arkansas, Louisiana, Mississippi, Minnesota and Oklahoma. NGD and electric operations in Texas do not have such mechanisms, although fixed customer charges are historically higher in Texas for NGD compared to our other jurisdictions. As a result, fluctuations from normal weather may have a positive or negative effect on NGD’s results in Texas and on CenterPoint Houston’s results in its service territory. We have historically entered into heating-degree day swaps for certain NGD jurisdictions to mitigate the effect of fluctuations from normal weather on its results of operations and cash flows for the winter heating season. However, NGD did not enter into heating-degree day swaps for the 2015–2016 winter season as a result of NGD’s Minnesota division implementing a full decoupling pilot in July 2015. We entered into a weather hedge for CenterPoint Houston’s service territory for the 2015–2016 winter season.consolidated financial statements.

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

~~CenterPoint Houston’s~~Houston Electric’s receivables from the distribution of electricity are collected from REPs that supply the electricity ~~CenterPoint~~ Houston Electric distributes to their customers. ~~Adverse~~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 ~~CenterPoint Houston’s~~Houston Electric’s services or could cause them to delay such payments. ~~CenterPoint~~ Houston ~~depends~~Electric depend on these REPs to remit payments on a timely basis, and any delay or default in payment by REPs could adversely affect ~~CenterPoint Houston’s~~Houston Electric’s cash flows. In the event of a REP’s default, ~~CenterPoint Houston’s~~Houston Electric’s tariff provides a number of remedies, including the option for ~~CenterPoint~~ Houston Electric to request that the ~~Texas Utility Commission~~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, ~~CenterPoint~~ Houston ~~remains~~Electric remain 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 ~~CenterPoint~~ Houston Electric involving payments it had received from such REP. If a REP were to file for bankruptcy, ~~CenterPoint~~ 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, ~~Texas Utility Commission~~PUCT regulations authorize utilities, such as ~~CEHE,~~Houston Electric, to defer bad debts resulting from defaults by REPs for recovery in future rate cases, subject to a review of reasonableness and necessity.

Other Factors that Could Affect Cash Requirements

In addition to the above factors, ~~our~~the Registrants’ liquidity and capital resources could be affected by:

cash collateral requirements that could exist in connection with certain contracts, including ~~our~~ weather hedging arrangements, and natural gas purchases, natural gas price and natural gas storage activities of ~~our~~CenterPoint Energy’s and CERC’s Natural Gas Distribution and Energy Services ~~business~~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;~~suppliers (CenterPoint Energy and CERC);

increased costs related to the acquisition of natural ~~gas;~~gas (CenterPoint Energy and CERC);

increases in interest expense in connection with debt refinancings and borrowings under credit facilities;

various legislative or regulatory actions;

incremental collateral, if any, that may be required due to regulation of ~~derivatives;~~

~~the ability of GenOn~~derivatives (CenterPoint Energy and its subsidiaries to satisfy their obligations in respect of GenOn’s indemnity obligations to us and our subsidiaries or in connection with the contractual obligations to a third party pursuant to which our subsidiary is their guarantor;CERC);

slower customer payments and increased write-offs of receivables due to higher natural gas prices or changing economic ~~conditions;~~conditions (CenterPoint Energy and CERC);

the outcome of ~~litigation brought by and against us;~~litigation;

contributions to pension and postretirement benefit ~~plans;~~plans (CenterPoint Energy);

restoration costs and revenue losses resulting from future natural disasters such as hurricanes and the timing of recovery of such restoration costs; and

various other risks identified in “Risk Factors” in Item 1A of Part I of this report.

Certain Contractual Limits on Our Ability to Issue Securities and Borrow Money

CenterPoint Houston’s revolving credit facility limits CenterPoint Houston’s consolidated debt (excluding transition and system restoration bonds) to an amount not to exceed 65% of its consolidated capitalization. CERC Corp.’s revolving credit facility limits CERC’s consolidated debt to an amount not to exceed 65% of its consolidated capitalization. Our revolving credit facility limits our consolidated debt (excluding transition and system restoration bonds) to an amount not to exceed 65% of our consolidated capitalization. The financial covenant limit in our revolving credit facility will temporarily increase from 65% to 70% if CenterPoint Houston ~~experiences damage from a natural disaster in its service territory that meets certain criteria. Additionally, CenterPoint 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’ 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 ~~our~~the Registrants’ financial condition and results of operations and requires management to make difficult, subjective or complex accounting estimates. An accounting estimate is an approximation made by management of a financial statement element, item or account in the financial statements. Accounting estimates in ~~our~~the Registrants’ historical consolidated financial statements measure the effects of past business transactions or events, or the present status of an asset or liability. The accounting estimates described below require usthe Registrants to make assumptions about matters that are highly uncertain at the time the estimate is made. Additionally, different estimates that wethe Registrants could have used or changes in an accounting estimate that are reasonably likely to occur could have a material impact on the presentation of ~~our~~their financial condition, results of operations or cash flows. The circumstances that make these judgments difficult, subjective and/or complex have to do with the need to make estimates about the effect of matters that are inherently uncertain. Estimates and assumptions about future events and their effects cannot be predicted with certainty. WeThe Registrants base ~~our~~their estimates on historical experience and on various other assumptions that wethey believe to be reasonable under the circumstances, the results of which form the basis for making judgments. These estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as ~~our~~the Registrants’ operating environment changes. ~~Our~~The Registrants’ significant accounting policies are discussed in Note 2 to ~~our~~the consolidated financial statements. WeThe Registrants believe the following accounting policies involve the application of critical accounting estimates. Accordingly, these accounting estimates have been reviewed and discussed with the ~~audit committee~~Audit Committee of ~~the board~~CenterPoint Energy’s Board of ~~directors.~~Directors.

Accounting for Rate Regulation

Accounting guidance for regulated operations provides that rate-regulated entities account for and report assets and liabilities consistent with the recovery of those incurred costs in rates if the rates established are designed to recover the costs of providing the regulated service and if the competitive environment makes it probable that such rates can be charged and collected. ~~Our~~CenterPoint Energy’s and Houston Electric’s Electric Transmission & Distribution ~~business~~reportable segment and ~~our~~CenterPoint Energy’s and CERC’s Natural Gas Distribution ~~business~~reportable segment apply this accounting guidance. Certain expenses and revenues subject to utility

regulation or rate determination normally reflected in income are deferred

on the balance sheet as regulatory assets or liabilities and are recognized in income as the related amounts are included in service rates and recovered from or refunded to customers. Regulatory assets and liabilities are recorded when it is probable that these items will be recovered or reflected in future rates. Determining probability requires significant judgment on the part of management and includes, but is not limited to, consideration of testimony presented in regulatory hearings, proposed regulatory decisions, final regulatory orders and the strength or status of applications for rehearing or state court appeals. If events were to occur that would make the recovery of these assets and liabilities no longer probable, wethe Registrants would be required to write off or write down these regulatory assets and liabilities. ~~As of~~ ~~December 31, 2015, we had recorded~~For further detail on the Registrants’ regulatory assets ~~of $3.1 billion~~ and ~~regulatory~~ liabilities, ~~of $1.3 billion.~~see Note 7 to the consolidated financial statements.

Impairment of Long-Lived Assets, Including Identifiable Intangibles, Goodwill, ~~and~~ Equity Method Investments, and Investments without a Readily Determinable Fair Value

WeThe Registrants review the carrying value of ~~our~~ long-lived assets, including identifiable intangibles, goodwill, ~~and~~ 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 for goodwill as required by accounting guidance for goodwill and other intangible assets. Unforeseen events and changes in market conditions could have a material effect on the value of long-lived assets, including intangibles, goodwill, ~~and~~ equity method investments, and investments without a readily determinable fair value due to changes in observable or estimated marked value, estimates of future cash flows, interest rate and regulatory matters and could result in an impairment charge. A loss in value of an equity method investment is recognized when the decline is deemed to be other than temporary. WeThe Registrants recorded no ~~goodwill impairments during 2015, 2014 and 2013. We did not record material~~ impairments to goodwill, long-lived assets, including intangibles, during 2015, 2014, and 2013. We recorded impairments totaling $1,225 million to our equity method investments during 2015 and no impairment during 2014 and 2013. See Notes 8 and 9 to our consolidated financial statements for further discussion of the impairments recorded to our equity method investment, ~~in 2015.~~or readily determinable fair value during 2018, 2017 and 2016.

WeCenterPoint Energy and CERC performed ~~our~~the annual goodwill impairment test in the third quarter of ~~2015~~2018 and determined, based primarily on ~~the results of the first step, using~~ the income approach, that no goodwill impairment charge was required for any reporting ~~unit. Our reporting units~~unit, which approximate ~~our~~the Registrants’ applicable reportable segments.

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

The determination of fair value requires significant assumptions by management which are subjective and forward-looking in nature. To assist in making these assumptions, weCenterPoint Energy and CERC utilized a third-party valuation specialist in both determining and testing key assumptions used in the valuation of each of ~~our~~the reporting units. WeCenterPoint Energy and CERC based ~~our~~their assumptions on projected financial information that wethey believe is reasonable; however, actual results may differ materially from those projections. These projected cash flows factor in planned growth initiatives, and for ~~our~~CenterPoint Energy’s and CERC’s Natural Gas Distribution reporting unit, the regulatory environment. The fair ~~value~~values of ~~our~~CenterPoint Energy’s and CERC’s Natural Gas Distribution and Energy Services reporting ~~unit~~units significantly exceeded the carrying ~~value. The fair value of our Energy Services reporting unit exceeded the carrying value by approximately $150 million or approximately 50% excess fair value over the carrying value.~~

A key assumption in the income approach was the weighted average cost of capital of 5.6% and 5.9% applied in the valuation for Natural Gas Distributions and Energy Services, respectively. An increase in the discount rate to greater than 7.2%, a decline in long-term growth rate from 3% to 1.7%, or a decrease in the aggregate cash flows of greater than 33% could have individually triggered a step-two goodwill impairment evaluation for our Energy Services reporting unit in 2015.values.

Although there was not a goodwill asset impairment in ~~our 2015~~the 2018 annual test, an interim impairment test could be triggered by the following: actual earnings results that are materially lower than expected, significant adverse changes in the operating environment, an increase in the discount rate, changes in other key assumptions which require judgment and are forward looking in nature, or if ~~our~~CenterPoint Energy’s market capitalization falls below book value for an extended period of time. No impairment triggers were identified subsequent to ~~our 2015~~the 2018 annual test.

We determined in connection with our preparation of financial statements for the three months ended September 30, 2015 and December 31, 2015, respectively, that an other than temporary decrease in the value of our investment in Enable had occurred. The impairment analysis compared the estimated fair value of our investment in Enable to its carrying value. The fair value of the investment was determined using multiple valuation methodologies under both the market and income approaches.

Key assumptions in the market approach include recent market transactions of comparable companies and EBITDA to total enterprise multiples for comparable companies. Due to volatility of the quoted price of Enable’s units, a volume weighted average price was used under the market approach to best approximate fair value at the measurement date. Key assumptions in the income

approach include Enable’s forecasted cash distributions, projected cash flows of incentive distribution rights, forecasted growth rate of Enable’s cash distributions beyond 2020, and the discount rate used to determine the present value of the estimated future cash flows. A weighing of the different approaches was utilized to determine the estimated fair value of our investment in Enable.

As a result of the analysis, we recorded other than temporary impairments on our investment in Enable of $250 million and $975 million during the three months ended September 30, 2015 and December 31, 2015, respectively. We based our assumptions on projected financial information that we believe is reasonable; however, actual results may differ materially from those projections. It is reasonably possible that the estimate of the impairment of our investment in Enable will change in the near term due to the following: actual Enable cash distribution is materially lower than expected, significant adverse changes in Enable’s operating environment, increase in the discount rate, and changes in other key assumptions which require judgment and are forward looking in nature.

Unbilled Energy Revenues

Revenues related to electricity delivery and natural gas sales and services are generally recognized upon delivery to customers. However, the determination of deliveries to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month either electronically through ~~advanced metering system (AMS)~~AMS meter communications or manual readings. At the end of each month, deliveries to non-AMS customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is estimated. Information regarding deliveries to AMS customers after the last billing is obtained from actual AMS meter usage data. Unbilled electricity delivery revenue is estimated each month based on actual AMS meter data, daily supply volumes and applicable rates. Unbilled natural gas sales are estimated based on estimated purchased gas volumes, estimated lost and unaccounted for gas and tariffed rates in effect. As additional information becomes available, or actual amounts are determinable, the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates.

Pension and Other Retirement Plans

~~We sponsor~~CenterPoint Energy sponsors pension and other retirement plans in various forms covering all employees who meet eligibility requirements. ~~We use~~CenterPoint Energy uses several statistical and other factors that attempt to anticipate future events in calculating the expense and liability related to ~~our~~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, ~~our~~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 expense recorded. Please read “— Other Significant Matters — Pension Plans” for further discussion.

NEW ACCOUNTING PRONOUNCEMENTS

See Note ~~2(o)~~2(r) to ~~our~~the consolidated financial statements, incorporated herein by reference, for a discussion of new accounting pronouncements that affect ~~us.~~the Registrants.

OTHER SIGNIFICANT MATTERS

Pension ~~Plans.~~Plans (CenterPoint Energy). As discussed in Note ~~6(b)~~8(b) to ~~our~~the consolidated financial statements, ~~we maintain~~CenterPoint Energy maintains a non-contributory qualified defined benefit pension plan covering substantially all employees. Employer contributions for the qualified plan are based on actuarial computations that establish the minimum contribution required under ~~the Employee Retirement Income Security Act of 1974 (ERISA)~~ERISA and the maximum deductible contribution for income tax purposes.

Under the terms of ~~our~~CenterPoint Energy’s pension plan, ~~we reserve~~it reserves the right to change, modify or terminate the plan. ~~Our~~CenterPoint Energy’s funding policy is to review amounts annually and contribute an amount at least equal to the minimum contribution required under ERISA.

~~The minimum funding requirements for the qualified pension plan were $-0-, $87 million and $83 million for~~ ~~2015~~, ~~2014~~ ~~and~~ ~~2013, respectively. We made contributions of $35 million, $87 million and $83 million in~~ ~~2015~~, ~~2014~~ ~~and~~ ~~2013~~ ~~for the respective years. We are not required to make any contribution in~~ ~~2016~~.

Additionally, ~~we maintain~~CenterPoint Energy maintains an unfunded non-qualified benefit restoration plan that allows participants to receive the benefits to which they would have been entitled under ~~our~~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. ~~Employer~~



	Year Ended December 31,
	2018		2017		2016
CenterPoint Energy	(in millions)
Minimum funding requirements for qualified pension plan	$	60	$	39	$	—
Employer contributions to the qualified pension plan	60		39		—
Employer contributions to the non-qualified benefit restoration plan	9		9		9

CenterPoint Energy expects to contribute a minimum of approximately $86 million to the qualified pension plan and contributions ~~for~~aggregating approximately $7 million to the non-qualified benefit restoration plan ~~represent benefit payments made to participants and totaled $31 million, $10 million~~in 2019.

~~and $8 million in~~ ~~2015~~, ~~2014~~ ~~and~~ ~~2013, respectively. We expect to make contributions aggregating approximately $8 million in~~ ~~2016~~.

Changes in pension obligations and assets may not be immediately recognized as pension expense in ~~the income statement,~~CenterPoint Energy’s Statements of Consolidated Income, but generally are recognized in future years over the remaining average service period of plan participants. As such, significant portions of pension expense recorded in any period may not reflect the actual level of benefit payments provided to plan participants.

As the sponsor of a plan, ~~we are~~CenterPoint Energy is required to (a) recognize on ~~our balance sheet~~its Consolidated Balance Sheet as an asset a plan’s over-funded status or as a liability such plan’s under-funded status, (b) measure a plan’s assets and obligations as of the end of ~~our~~the fiscal year and (c) recognize changes in the funded status of ~~our~~the plans in the year that changes occur through adjustments to other comprehensive income and, when related to its rate-regulated utilities with recovery mechanisms, to regulatory assets.

The projected benefit obligation for all defined benefit pension plans was ~~$2,193~~$2,013 million and ~~$2,403~~$2,225 million as of December 31, ~~2015~~2018 and ~~2014,~~2017, respectively. ~~The adoption of the new mortality table by the Society of Actuaries as of December 31, 2014 significantly contributed to the increase in the projected benefit obligation for 2014.~~

As of December 31, ~~2015~~2018, the projected benefit obligation exceeded the market value of plan assets of ~~our~~CenterPoint Energy’s pension plans by ~~$514~~$497 million. Changes in interest rates or the market values of the securities held by the plan during ~~2016~~2019 could materially, positively or negatively, change ~~our~~the funded status and affect the level of pension expense and required contributions.

Pension cost was $90 million, $77 million and $72 million for 2015, 2014 and 2013, respectively, of which $59 million, $71 million and $64 million impacted pre-tax earnings, respectively. Included in the 2015 and 2014 pension costs were a $10 million settlement charge and $6 million curtailment loss, respectively, as discussed below.

~~A one-time, non-cash settlement charge is required when lump sum distributions or other settlements of plan benefit obligations during the year exceed the service~~

Houston Electric and CERC participate in CenterPoint Energy’s qualified and non-qualified pension plans covering substantially all employees. Pension cost and ~~interest cost components of net periodic cost for~~ the ~~year. Due~~impact to the amount of lump sum payment distributions from the non-qualified pension plan during the year ended December 31, 2015, CenterPoint Energy recognized a non-cash settlement charge of $10 million. This charge is an acceleration of costs that would otherwise be recognized in future periods. pre-tax earnings, after capitalization and regulatory impacts, by Registrant were as follows:



	Year Ended December 31,
	2018						2017						2016
	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC
	(in millions)
Pension cost	$	61	$	25	$	22	$	95	$	42	$	35	$	102	$	45	$	37
Impact to pre-tax earnings	64		27		23		71		23		29		67		20		28

During the fourth quarter of 2014, CenterPoint Energy received notification from Enable of its intent to provide employment offers to substantially all seconded employees. As a result, an additional pension cost of $6 million was recognized for the curtailment loss related to our pension plans. Substantially all of the seconded employees became employees of Enable effective January 1, 2015.

The calculation of pension ~~expense~~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, ~~2015~~2018, ~~our~~CenterPoint Energy’s qualified pension plan had an expected long-term rate of return on plan assets of ~~6.25%~~6.00%, which is ~~a 0.25% decrease~~unchanged from the rate assumed as of December 31, ~~2014~~2017 ~~due to lower expected capital market return rates.~~. The expected rate of return assumption was developed using the targeted asset allocation of our plans and the expected return for each asset class. WeCenterPoint Energy regularly ~~review our~~reviews its actual asset allocation and periodically ~~rebalance~~rebalances plan assets to reduce volatility and better match plan assets and liabilities.

As of December 31, ~~2015~~2018, the projected benefit obligation was calculated assuming a discount rate of ~~4.40%~~4.35%, which is ~~0.35%~~0.70% higher than the ~~4.05%~~3.65% discount rate assumed inas of ~~2014~~December 31, 2017. The discount rate was determined by reviewing yields on high-quality bonds that receive one of the two highest ratings given by a recognized rating agency and the expected duration of pension obligations specific to the characteristics of ~~our~~CenterPoint Energy’s plan.

CenterPoint Energy’s actuarially determined pension and other postemployment expense for 2018 and 2017 that is greater or less than the amounts being recovered through rates in certain jurisdictions is deferred as a regulatory asset or liability, respectively. Pension cost for ~~2016~~2019, including the benefit restoration plan, is estimated to be ~~$102~~$93 million, of which ~~we expect $66~~CenterPoint Energy expects approximately $70 million to impact pre-tax earnings after effecting such deferrals and capitalization, based on an expected return on plan assets of ~~6.25%~~6.00% and a discount rate of ~~4.40%~~4.35% as of December 31, ~~2015~~2018. If the expected return assumption were lowered by 0.50% from ~~6.25%~~6.00% to ~~5.75%~~5.50%, ~~2016~~2019 pension cost would increase by approximately $8$7 million.

As of December 31, ~~2015~~2018, the pension plan projected benefit obligation, including the unfunded benefit restoration plan, exceeded plan assets by ~~$514~~$497 million. If the discount rate were lowered by 0.50% from ~~4.40%~~4.35% to ~~3.90%~~3.85%, the assumption change would increase ~~our~~CenterPoint Energy’s projected benefit obligation by approximately ~~$115~~$98 million and decrease ~~our 2016~~its 2019 pension ~~expense~~cost by approximately $2 million. The expected reduction in pension ~~expense~~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 ~~our~~CenterPoint Energy’s Consolidated Balance ~~Sheet~~Sheets by increasing the regulatory asset recorded as of December 31, ~~2015~~2018 by ~~$101~~$84 million and would result in a charge to comprehensive income in ~~2015~~2018 of $9$11 million, net of ~~tax.~~tax of $3 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 ~~plan~~plans will impact ~~our~~CenterPoint Energy’s future pension expense and liabilities. WeCenterPoint Energy cannot predict with certainty what these factors will be in the future.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Impact of Changes in Interest Rates, Equity Prices and Energy Commodity Prices

WeThe Registrants are exposed to various market risks. These risks arise from transactions entered into in the normal course of business and are inherent in ~~our~~the Registrants’ consolidated financial statements. Most of the revenues and income from ~~our~~the Registrants’ business activities are affected by market risks. Categories of market risk include exposure to commodity prices through non-trading activities, interest rates and equity prices. A description of each market risk is set forth below:

Interest rate risk primarily results from exposures to changes in the level of borrowings and changes in interest rates.

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

Commodity price risk results from exposures to changes in spot prices, forward prices and price volatilities of commodities, such as natural gas, ~~natural gas liquids~~NGLs and other energy ~~commodities.~~commodities (CenterPoint Energy and CERC).

Management has established comprehensive risk management policies to monitor and manage these market risks. We manage these risk exposures through the implementation of our risk management policies and framework. We manage our commodity price risk exposures through the use of derivative financial instruments and derivative commodity instrument contracts. During the normal course of business, we review our hedging strategies and determine the hedging approach we deem appropriate based upon the circumstances of each situation.

Derivative instruments such as futures, forward contracts, swaps and options derive their value from underlying assets, indices, reference rates or a combination of these factors. These derivative instruments include negotiated contracts, which are referred to as over-the-counter derivatives, and instruments that are listed and traded on an exchange.

Derivative transactions are entered into in our non-trading operations to manage and hedge certain exposures, such as exposure to changes in natural gas prices. We believe that the associated market risk of these instruments can best be understood relative to the underlying assets or risk being hedged.

Interest Rate Risk

As of December 31, ~~2015~~2018, wethe Registrants had outstanding long-term debt and lease obligations and CenterPoint Energy had obligations under ~~our~~its ZENS that subject usthem to the risk of loss associated with movements in market interest rates.

~~Our~~CenterPoint Energy’s floating rate obligations aggregated ~~$1.1~~$210 million and $1.8 billion ~~and $532 million~~ as of December 31, ~~2015~~2018 and ~~2014,~~2017, respectively. If the floating interest rates were to increase by 10% from December 31, ~~2015~~2018 rates, ~~our~~CenterPoint Energy’s combined interest expense would increase by approximately $1 million annually.

Houston Electric did not have any floating rate obligations as of either December 31, 2018 or 2017.

CERC’s floating rate obligations aggregated $210 million and $1.5 billion at December 31, 2018 and 2017, respectively. If the floating interest rates were to increase by 10% from December 31, 2018 rates, CERC’s combined interest expense would increase by approximately $1 million annually.

As of December 31, ~~2015~~2018 and ~~2014, we~~2017, CenterPoint Energy had outstanding fixed-rate debt (excluding indexed debt securities) aggregating ~~$7.5~~$9.0 billion and ~~$8.2~~$7.0 billion, respectively, in principal amount and having a fair value of ~~$8.0~~$9.2 billion and ~~$8.9~~$7.5 billion, respectively. Because these instruments are fixed-rate, they do not expose usCenterPoint Energy to the risk of loss in earnings due to changes in market interest ~~rates (see Note 12 to our consolidated financial statements).~~rates. However, the fair value of these instruments would increase by approximately ~~$216~~$286 million if interest rates were to decline by 10% from their levels as of December 31, 2018.

As of December 31, 2018 and 2017, Houston Electric had outstanding fixed-rate debt aggregating $4.8 billion and $4.8 billion, respectively, in principal amount and having a fair value of approximately $4.8 billion and $5.1 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 $158 million if interest rates were to decline by 10% from their levels as of December 31, 2018.

As of December 31, 2018 and 2017, CERC had outstanding fixed-rate debt aggregating $2.2 billion and $1.6 billion, respectively, in principal amount and having a fair value of $2.3 billion and $1.8 billion, respectively. Because these instruments are fixed-rate, they do not expose CERC to the risk of loss in earnings due to changes in market interest rates. However, the fair value of these instruments would increase by approximately $89 million if interest rates were to decline by 10% from their levels at December 31, ~~2015~~. 2018.

In general, such an increase in fair value would impact earnings and cash flows only if wethe Registrants were to reacquire all or a portion of these instruments in the open market prior to their maturity.

As discussed in Note 1012 to ~~our~~the consolidated financial statements, the ZENS obligation is bifurcated into a debt component and a derivative component. The debt component of ~~$154~~$24 million at December 31, ~~2015~~2018 was a fixed-rate obligation and, therefore, did not expose usCenterPoint Energy to the risk of loss in earnings due to changes in market interest rates. However, the fair value of the debt component would increase by approximately ~~$24~~$3 million if interest rates were to decline by 10% from levels at December 31, ~~2015~~2018. Changes

in the fair value of the derivative component, a ~~$442~~$601 million recorded liability at December 31, ~~2015~~2018, are recorded in ~~our~~CenterPoint Energy’s Statements of Consolidated Income and, therefore, ~~we are~~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, ~~2015~~2018 levels, the fair value of the derivative component liability would ~~increase~~decrease by approximately $8$2 million, which would be recorded as an unrealized ~~loss~~gain in ~~our~~CenterPoint Energy’s Statements of Consolidated Income.

Equity Market Value Risk (CenterPoint Energy)

~~We are~~CenterPoint Energy is exposed to equity market value risk through ~~our~~its ownership of ~~7.1~~10.2 million shares of ~~TW Common, 1.8 million shares of TWC~~AT&T Common and 0.9 million shares of ~~Time~~Charter Common, which ~~we hold~~CenterPoint Energy holds to facilitate ~~our~~its ability to meet ~~our~~its obligations under the ZENS. See Note 1012 to ~~our~~the consolidated financial statements for a discussion of ~~our~~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, ~~2015~~2018 aggregate market value of these shares would result in a net loss of ~~approximately $14~~less than $1 million, which would be recorded as an unrealized loss in ~~our~~CenterPoint Energy’s Statements of Consolidated Income.

Commodity Price Risk From Non-Trading Activities (CenterPoint Energy and CERC)

WeCenterPoint Energy and CERC use derivative instruments as economic hedges to offset the commodity price exposure inherent in ~~our~~their businesses. The ~~stand-alone~~ commodity risk created by these instruments, ~~without regard to~~including the offsetting ~~effect~~impact on the market value of ~~the underlying exposure these instruments are intended to hedge,~~natural gas inventory, is described below. WeCenterPoint Energy and CERC measure ~~the~~this commodity risk ~~of our non-trading energy derivatives~~ using a sensitivity analysis. ~~The sensitivity~~For purposes of this analysis, ~~performed on our non-trading energy derivatives measures~~CenterPoint Energy and CERC estimate commodity price risk by applying a $0.50 change in the ~~potential loss in fair value based on a hypothetical 10% movement in energy prices. At~~ 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, ~~2015~~,2018, the recorded fair value of ~~our~~CenterPoint Energy’s and CERC’s non-trading energy derivatives was a net asset of ~~$53~~$12 million (before collateral), all of which is related to ~~our~~CenterPoint Energy’s and CERC’s Energy Services ~~business~~reportable segment. ~~An increase of 10%~~A $0.50 change in the ~~market prices of energy commodities from their~~ ~~December 31, 2015~~ ~~levels~~forward NYMEX price would have ~~decreased the fair value~~had a combined impact of ~~our~~$7 million on CenterPoint Energy’s and CERC’s non-trading energy derivatives net asset ~~by $6 million.~~

~~The above analysis of~~and the non-trading energy derivatives utilized for commodity price risk management purposes does not include the favorable impact that the same hypothetical price movement would have on our non-derivative physical purchases and salesmarket value of natural gas inventory.

Commodity price risk is not limited to ~~which~~changes in forward NYMEX prices. Variation of commodity pricing between the ~~hedges relate. Furthermore,~~different indices used to mark to market portions of CenterPoint Energy’s and CERC’s natural gas inventory (Gas Daily) and the ~~non-trading energy derivative portfolio is managed~~related fair value hedge (NYMEX) can result in volatility to ~~complement~~CenterPoint Energy’s and CERC’s net income. Over time, any gains or losses on the ~~physical transaction portfolio, reducing overall risks within limits. Therefore, the adverse impact to~~sale of storage gas inventory would be offset by gains or losses on the fair value of the portfolio of non-trading energy derivatives held for hedging purposes associated with the hypothetical changes in commodity prices referenced above is expected to be substantially offset by a favorable impact on the underlying hedged physical transactions.hedges.

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, ~~2015~~2018 and ~~2014, and~~2017, the related statements of consolidated income, comprehensive income, ~~shareholders’~~changes in equity, and cash flows, for each of the three years in the period ended December 31, ~~2015~~2018, 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, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, 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, 2018, 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 28, 2019, 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 ~~these~~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 ~~Public Company Accounting Oversight Board (United States).~~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. An audit includes~~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 ~~supporting~~regarding the amounts and disclosures in the financial statements. ~~An audit~~Our audits also ~~includes assessing~~included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial ~~statement presentation.~~statements. We believe that our audits provide a reasonable basis for our opinion.

~~In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of CenterPoint Energy, Inc. and subsidiaries as of~~ ~~December 31, 2015~~ ~~and~~ ~~2014, and the results of their operations and their cash flows for each of the three years in the period ended~~ ~~December 31, 2015, 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), the Company’s internal control over financial reporting as of~~ ~~December 31, 2015, based on the criteria established in~~ ~~Internal Control—Integrated Framework~~ ~~(2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated~~ ~~February 26, 2016~~ ~~expressed an unqualified opinion on the Company’s internal control over financial reporting.~~

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

February ~~26, 2016~~28, 2019

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

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED INCOME

Year Ended December 31,
2015 2014 2013
(in millions, except per share amounts)
Revenues $ 7,386
$ 9,226
$ 8,106
Expenses:

Natural gas 3,102
4,921
3,908
Operation and maintenance 2,007
1,969
1,847
Depreciation and amortization 970
1,013
954
Taxes other than income taxes 374
388
387
Total 6,453
8,291
7,096
Operating Income 933
935
1,010
Other Income (Expense):
Gain (Loss) on marketable securities (93 ) 163
236
Gain (Loss) on indexed debt securities 74
(86 ) (193 )
Interest and other finance charges (352 ) (353 ) (351 )
Interest on transition and system restoration bonds (105 ) (118 ) (133 )
Equity in earnings (losses) of unconsolidated affiliates (1,633 ) 308
188
Other, net 46
36
24
Total (2,063 ) (50 ) (229 )
Income (Loss) Before Income Taxes (1,130 ) 885
781
Income tax expense (benefit) (438 ) 274
470
Net Income (Loss) $ (692 ) $ 611
$ 311

Basic Earnings (Loss) Per Share $ (1.61 ) $ 1.42
$ 0.73

Diluted Earnings (Loss) Per Share $ (1.61 ) $ 1.42
$ 0.72

Weighted Average Shares Outstanding, Basic 430
430
428

Weighted Average Shares Outstanding, Diluted 430
432
431



	Year Ended December 31,
	2018			2017			2016
	(in millions, except per share amounts)
Revenues:
Utility revenues	$	6,163		$	5,603		$	5,440
Non-utility revenues	4,426			4,011			2,088
Total	10,589			9,614			7,528
Expenses:
Utility natural gas	1,410			1,109			983
Non-utility natural gas	4,364			3,785			1,983
Operation and maintenance	2,335			2,157			2,029
Depreciation and amortization	1,243			1,036			1,126
Taxes other than income taxes	406			391			384
Total	9,758			8,478			6,505
Operating Income	831			1,136			1,023
Other Income (Expense):
Gain (loss) on marketable securities	(22		)	7			326
Gain (loss) on indexed debt securities	(232		)	49			(413		)
Interest and other finance charges	(361		)	(313		)	(338		)
Interest on Securitization Bonds	(59		)	(77		)	(91		)
Equity in earnings of unconsolidated affiliates, net	307			265			208
Other, net	50			(4		)	(29		)
Total	(317		)	(73		)	(337		)
Income Before Income Taxes	514			1,063			686
Income tax expense (benefit)	146			(729		)	254
Net Income	368			1,792			432
Preferred stock dividend requirement	35			—			—
Income Available to Common Shareholders	$	333		$	1,792		$	432

Basic Earnings Per Common Share	$	0.74		$	4.16		$	1.00

Diluted Earnings Per Common Share	$	0.74		$	4.13		$	1.00

Weighted Average Common Shares Outstanding, Basic	449			431			431

Weighted Average Common Shares Outstanding, Diluted	452			434			434

See Combined Notes to Consolidated Financial Statements

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME

Year Ended December 31,
2015 2014 2013
(in millions)
Net income (loss) $ (692 ) $ 611
$ 311
Other comprehensive income:

Adjustment to pension and other postretirement plans (net of tax of $12, $5 and $25, respectively) 20
3
44
Reclassification of deferred loss from cash flow hedges realized in net income (net of tax) —
1
1
Other comprehensive income 20
4
45
Comprehensive income (loss) $ (672 ) $ 615
$ 356



	Year Ended December 31,
	2018			2017			2016
	(in millions)
Net income	$	368		$	1,792		$	432
Other comprehensive income (loss):
Adjustment to pension and other postretirement plans (net of tax expense (benefit) of ($2), $6 and ($4), respectively)	(10		)	6			(7		)
Net deferred gain (loss) from cash flow hedges (net of tax expense (benefit) of ($4), ($2), and $-0-, respectively)	(15		)	(3		)	1
Reclassification of deferred loss from cash flow hedges realized in net income (net of tax expense of $-0-, $-0-, and $1, respectively)	—			—			1
Other comprehensive income (loss)	(25		)	3			(5		)
Comprehensive income	343			1,795			427
Preferred stock dividend requirement	35			—			—
Comprehensive income available to common shareholders	$	308		$	1,795		$	427

See Combined Notes to Consolidated Financial Statements

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

December 31,
2015 December 31,
2014
(in millions)
ASSETS
Current Assets:
Cash and cash equivalents ($264 and $290 related to VIEs, respectively) $ 264
$ 298
Investment in marketable securities 805
930
Accounts receivable ($64 and $58 related to VIEs, respectively), less bad debt reserve of $20 and $26, respectively 593
837
Accrued unbilled revenues 279
357
Inventory 347
379
Non-trading derivative assets 89
99
Taxes receivable 172
190
Prepaid expense and other current assets ($35 and $47 related to VIEs, respectively) 140
178
Total current assets 2,689
3,268
Property, Plant and Equipment, net 11,537
10,502
Other Assets:

Goodwill 840
840
Regulatory assets ($2,373 and $2,738 related to VIEs, respectively) 3,129
3,527
Notes receivable - affiliated companies 363
363
Non-trading derivative assets 36
32
Investment in unconsolidated affiliates 2,594
4,521
Other 146
147
Total other assets 7,108
9,430
Total Assets $ 21,334
$ 23,200
LIABILITIES AND SHAREHOLDERS’ EQUITY

Current Liabilities:

Short-term borrowings $ 40
$ 53
Current portion of VIE transition and system restoration bonds long-term debt 391
372
Indexed debt 154
152
Current portion of other long-term debt 328
271
Indexed debt securities derivative 442
541
Accounts payable 483
716
Taxes accrued 158
161
Interest accrued 117
124
Non-trading derivative liabilities 11
19
Other 343
383
Total current liabilities 2,467
2,792
Other Liabilities:

Deferred income taxes, net 5,047
5,440
Non-trading derivative liabilities 5
1
Benefit obligations 904
953
Regulatory liabilities 1,276
1,206
Other 273
251
Total other liabilities 7,505
7,851
Long-term Debt:

VIE transition and system restoration bonds 2,283
2,674
Other long-term debt 5,618
5,335
Total long-term debt 7,901
8,009
Commitments and Contingencies (Note 14)

Shareholders’ Equity 3,461
4,548
Total Liabilities and Shareholders’ Equity $ 21,334
$ 23,200



	December 31, 2018		December 31, 2017
	(in millions)
ASSETS
Current Assets:
Cash and cash equivalents ($335 and $230 related to VIEs, respectively)	$	4,231	$	260
Investment in marketable securities	540		960
Accounts receivable ($56 and $73 related to VIEs, respectively), less bad debt reserve of $18 and $19, respectively	1,190		1,000
Accrued unbilled revenues	378		427
Natural gas inventory	194		222
Materials and supplies	200		175
Non-trading derivative assets	100		110
Prepaid expense and other current assets ($34 and $35 related to VIEs, respectively)	192		241
Total current assets	7,025		3,395
Property, Plant and Equipment, net	14,044		13,057
Other Assets:
Goodwill	867		867
Regulatory assets ($1,059 and $1,590 related to VIEs, respectively)	1,967		2,347
Non-trading derivative assets	38		44
Investment in unconsolidated affiliates	2,482		2,472
Preferred units - unconsolidated affiliate	363		363
Other	223		191
Total other assets	5,940		6,284
Total Assets	$	27,009	$	22,736

See Combined Notes to Consolidated Financial Statements

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS, cont.



	December 31, 2018			December 31, 2017
	(in millions, except par value and shares)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities:
Short-term borrowings	$	—		$	39
Current portion of VIE Securitization Bonds long-term debt	458			434
Indexed debt, net	24			122
Current portion of other long-term debt	—			50
Indexed debt securities derivative	601			668
Accounts payable	1,240			963
Taxes accrued	204			181
Interest accrued	121			104
Dividends accrued	187			120
Non-trading derivative liabilities	126			20
Other	341			368
Total current liabilities	3,302			3,069
Other Liabilities:
Deferred income taxes, net	3,239			3,174
Non-trading derivative liabilities	5			4
Benefit obligations	796			785
Regulatory liabilities	2,525			2,464
Other	402			357
Total other liabilities	6,967			6,784
Long-term Debt:
VIE Securitization Bonds, net	977			1,434
Other long-term debt, net	7,705			6,761
Total long-term debt, net	8,682			8,195
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			—
Series B Preferred Stock, $0.01 par value, $978 aggregate liquidation preference, 977,500 shares outstanding	950			—
Common stock, $0.01 par value, 1,000,000,000 shares authorized, 501,197,784 shares and 431,044,845 shares outstanding, respectively	5			4
Additional paid-in capital	6,072			4,209
Retained earnings	349			543
Accumulated other comprehensive loss	(108		)	(68		)
Total shareholders’ equity	8,058			4,688
Total Liabilities and Shareholders’ Equity	$	27,009		$	22,736

See Combined Notes to Consolidated Financial Statements

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED CASH FLOWS


	Year Ended December 31,									Year Ended December 31,
	2015			2014			2013			2018			2017			2016
	(in millions)									(in millions)
Cash Flows from Operating Activities:
Net income (loss)	$	(692	)	$	611		$	311
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Net income										$	368		$	1,792		$	432
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	970			1,013			954			1,243			1,036			1,126
Amortization of deferred financing costs	27			28			30			48			24			26
Deferred income taxes	(413		)	280			356			48			(770		)	213
Unrealized loss (gain) on marketable securities	93			(163		)	(236		)	22			(7		)	(326		)
Loss (gain) on indexed debt securities	(74		)	86			193			232			(49		)	413
Write-down of natural gas inventory	4			8			4			2			—			1
Equity in (earnings) losses of unconsolidated affiliates, net of distributions	1,779			(2		)	(58		)
Equity in earnings of unconsolidated affiliates, net of distributions										(40		)	(265		)	(208		)
Pension contributions	(66		)	(97		)	(91		)	(69		)	(48		)	(9		)
Changes in other assets and liabilities:
Changes in other assets and liabilities, excluding acquisitions:
Accounts receivable and unbilled revenues, net	345			39			(256		)	(154		)	(216		)	(117		)
Inventory	28			(102		)	(22		)	1			(7		)	34
Taxes receivable	18			(190		)	7			—			30			142
Accounts payable	(224		)	(3		)	152			220			136			133
Fuel cost recovery	43			(41		)	108			33			(85		)	(72		)
Non-trading derivatives, net	(7		)	(34		)	4			103			(84		)	30
Margin deposits, net	(4		)	(79		)	16			5			(55		)	101
Interest and taxes accrued	(10		)	(23		)	41			40			5			5
Net regulatory assets and liabilities	63			22			61			28			(107		)	(60		)
Other current assets	10			1			(2		)	—			(3		)	(25		)
Other current liabilities	(50		)	(20		)	21			(24		)	34			22
Other assets	(5		)	9			(24		)	6			(4		)	(16		)
Other liabilities	8			41			20			12			36			30
Other, net	22			13			24			12			24			48
Net cash provided by operating activities	1,865			1,397			1,613			2,136			1,417			1,923
Cash Flows from Investing Activities:
Capital expenditures	(1,584		)	(1,372		)	(1,286		)	(1,651		)	(1,426		)	(1,414		)
Acquisitions, net of cash acquired										—			(132		)	(102		)
Decrease in notes receivable - unconsolidated affiliate										—			—			363
Investment in preferred units - unconsolidated affiliate										—			—			(363		)
Distributions from unconsolidated affiliates in excess of cumulative earnings	148			—			—			30			297			297
Decrease (increase) in restricted cash of transition and system restoration bond companies	12			(7		)	17
Investment in unconsolidated affiliates	—			(1		)	—
Cash contribution to Enable	—			—			(38		)
Proceeds from sale of marketable securities	32			—			9			398			—			178
Other, net	5			(4		)	(2		)	16			4			7
Net cash used in investing activities	(1,387		)	(1,384		)	(1,300		)	(1,207		)	(1,257		)	(1,034		)
Cash Flows from Financing Activities:
Increase (decrease) in short-term borrowings, net	(13		)	10			5			(39		)	4			(5		)
Proceeds from commercial paper, net	403			414			118
Proceeds from long-term debt	—			600			1,050
Proceeds from (payments of) commercial paper, net										(1,543		)	349			469
Proceeds from long-term debt, net										2,495			1,096			600
Payments of long-term debt	(644		)	(537		)	(1,573		)	(484		)	(1,211		)	(1,218		)
Long-term revolving credit facility	200			—			—
Cash paid for debt exchange and debt retirement	—			(1		)	(7		)
Debt issuance costs	—			(8		)	(3		)
Redemption of indexed debt securities	—			—			(8		)
Payment of common stock dividends	(426		)	(408		)	(355		)
Proceeds from issuance of common stock, net	—			1			4
Loss on reacquired debt										—			(5		)	(22		)
Debt and equity issuance costs										(47		)	(13		)	(9		)
Payment of dividends on Common Stock										(499		)	(461		)	(443		)
Payment of dividends on preferred stock										(11		)	—			—
Proceeds from issuance of Common Stock, net										1,844			—			—
Proceeds from issuance of preferred stock, net										1,740			—			—
Distribution to ZENS holders	(32		)	—			—			(398		)	—			(178		)
Other, net	—			6			18			(5		)	(4		)	(2		)
Net cash provided by (used in) financing activities	(512		)	77			(751		)	3,053			(245		)	(808		)
Net Increase (Decrease) in Cash and Cash Equivalents	(34		)	90			(438		)
Cash and Cash Equivalents at Beginning of Year	298			208			646
Cash and Cash Equivalents at End of Year	$	264		$	298		$	208

Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash										3,982			(85		)	81
Cash, Cash Equivalents and Restricted Cash at Beginning of Year										296			381			300
Cash, Cash Equivalents and Restricted Cash at End of Year										$	4,278		$	296		$	381

See Combined Notes to Consolidated Financial Statements

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED ~~CASH FLOWS, cont.~~CHANGES IN EQUITY

Year Ended December 31,
2015 2014 2013
(in millions)
Supplemental Disclosure of Cash Flow Information:

Cash Payments:

Interest, net of capitalized interest $ 426
$ 434
$ 475
Income taxes (refunds), net (45 ) 192
35
Non-cash transactions:

Accounts payable related to capital expenditures 95
104
74
Formation of Enable —
—
4,252
Exercise of SESH put to Enable 1
196
—



	2018					2017				2016
	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	—	$	—			—	$	—		—	$	—
Issuances of Series A Preferred Stock	1	790				—	—			—	—
Issuances of Series B Preferred Stock	1	950				—	—			—	—
Balance, end of year	2	1,740				—	—			—	—
Common Stock, $0.01 par value; authorized 1,000,000,000 shares
Balance, beginning of year	431	4				431	4			430	4
Issuances related to benefit and investment plans	—	—				—	—			1	—
Issuances of Common Stock	70	1				—	—			—	—
Balance, end of year	501	5				431	4			431	4
Additional Paid-in-Capital
Balance, beginning of year		4,209					4,195				4,180
Issuances related to benefit and investment plans		19					14				15
Issuances of Common Stock, net of issuance costs		1,844					—				—
Balance, end of year		6,072					4,209				4,195
Retained Earnings (Accumulated Deficit)
Balance, beginning of year		543					(668		)		(657		)
Net income		368			0.000372		1,792				432
Common Stock dividends declared ($1.12, $1.3475 and $1.03 per share, respectively)		(523		)			(581		)		(443		)
Series A Preferred Stock dividends declared ($32.1563, $-0- and $-0- per share, respectively)		(26		)			—				—
Series B Preferred Stock dividends declared ($29.1667, $-0- and $-0- per share, respectively)		(28		)			—				—
Adoption of ASU 2018-02		15					—				—
Balance, end of year		349					543				(668		)
Accumulated Other Comprehensive Loss
Balance, beginning of year		(68		)			(71		)		(66		)
Other comprehensive income (loss)		(25		)			3				(5		)
Adoption of ASU 2018-02		(15		)			—				—
Balance, end of year		(108		)			(68		)		(71		)
Total Shareholders’ Equity		$	8,058				$	4,688			$	3,460

See Combined Notes to Consolidated Financial Statements

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, 2018 and 2017, 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, 2018, 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, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, 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 28, 2019

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

CENTERPOINT ENERGY ~~INC.~~HOUSTON ELECTRIC, LLC AND SUBSIDIARIES

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

STATEMENTS OF CONSOLIDATED ~~SHAREHOLDERS’ EQUITY~~

INCOME

2015 2014 2013
Shares Amount Shares Amount Shares Amount
(in millions of dollars and shares)
Preference Stock, none outstanding —
$ —
—
$ —
—
$ —
Cumulative Preferred Stock, $0.01 par value; authorized 20,000,000 shares, none outstanding —
—
—
—
—
—
Common Stock, $0.01 par value; authorized 1,000,000,000 shares

Balance, beginning of year 430
4
429
4
428
4
Issuances related to benefit and investment plans —
—
1
—
1
—
Balance, end of year 430
4
430
4
429
4
Additional Paid-in-Capital

Balance, beginning of year 4,169

4,157
4,130
Issuances related to benefit and investment plans 11

12
27
Balance, end of year 4,180

4,169
4,157
Retained Earnings (Accumulated Deficit)

Balance, beginning of year 461

258
302
Net income (loss) (692 )
611
311
Common stock dividends (426 )
(408 ) (355 )
Balance, end of year (657 )
461
258
Accumulated Other Comprehensive Loss

Balance, end of year:

Adjustment to pension and postretirement plans (65 )
(85 ) (88 )
Net deferred loss from cash flow hedges (1 )
(1 ) (2 )
Total accumulated other comprehensive loss, end of year (66 )
(86 ) (90 )
Total Shareholders’ Equity $ 3,461

$ 4,548
$ 4,329



	Year Ended December 31,
	2018			2017			2016
	(in millions)
Revenues	$	3,234		$	2,998		$	3,059

Expenses:
Operation and maintenance	1,452			1,402			1,338
Depreciation and amortization	917			724			838
Taxes other than income taxes	240			235			231
Total	2,609			2,361			2,407
Operating Income	625			637			652

Other Income (Expense):
Interest and other finance charges	(138		)	(128		)	(126		)
Interest on Securitization Bonds	(59		)	(77		)	(91		)
Other, net	(3		)	(8		)	(10		)
Total	(200		)	(213		)	(227		)
Income Before Income Taxes	425			424			425
Income tax expense (benefit)	89			(9		)	149
Net Income	$	336		$	433		$	276

See Combined Notes to Consolidated Financial Statements

CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC AND SUBSIDIARIES

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

STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME



	Year Ended December 31,
	2018			2017			2016
	(in millions)
Net income	$	336		$	433		$	276
Other comprehensive income (loss):
Net deferred gain (loss) from cash flow hedges (net of tax expense (benefit) of ($4), $-0-, and $-0-)	(14		)	(1		)	1
Other comprehensive income (loss):	(14		)	(1		)	1
Comprehensive income	$	322		$	432		$	277

See Combined Notes to Consolidated Financial Statements

CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC AND SUBSIDIARIES

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

CONSOLIDATED BALANCE SHEETS



	December 31, 2018			December 31, 2017
	(in millions)
ASSETS
Current Assets:
Cash and cash equivalents ($335 and $230 related to VIEs, respectively)	$	335		$	238
Accounts and notes receivable, net ($56 and $73 related to VIEs, respectively), less bad debt reserve of $1 and $1, respectively	283			284
Accounts and notes receivable—affiliated companies	20			7
Accrued unbilled revenues	110			120
Materials and supplies	135			119
Taxes receivable	5			—
Other ($34 and $35 related to VIEs, respectively)	61			62
Total current assets	949			830
Property, Plant and Equipment, net	8,402			7,863
Other Assets:
Regulatory assets ($1,059 and $1,590 related to VIEs, respectively)	1,124			1,570
Other	32			29
Total other assets	1,156			1,599
Total Assets	$	10,507		$	10,292

LIABILITIES AND MEMBER’S EQUITY
Current Liabilities:
Current portion of VIE Securitization Bonds long-term debt	$	458		$	434
Accounts payable	262			243
Accounts and notes payable—affiliated companies	78			104
Taxes accrued	115			116
Interest accrued	64			65
Non-trading derivative liabilities	24			—
Other	89			120
Total current liabilities	1,090			1,082
Other Liabilities:
Deferred income taxes, net	1,023			1,059
Benefit obligations	91			146
Regulatory liabilities	1,298			1,263
Other	65			54
Total other liabilities	2,477			2,522
Long-Term Debt, net:
VIE Securitization Bonds, net	977			1,434
Other long-term debt, net	3,281			2,885
Total long-term debt, net	4,258			4,319
Commitments and Contingencies (Note 16)
Member’s Equity:
Common stock	—			—
Paid-in capital	1,896			1,696
Retained earnings	800			673
Accumulated other comprehensive loss	(14		)	—
Total member’s equity	2,682			2,369
Total Liabilities and Member’s Equity	$	10,507		$	10,292

See Combined Notes to Consolidated Financial Statements

CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC AND SUBSIDIARIES

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

STATEMENTS OF CONSOLIDATED CASH FLOWS



	Year Ended December 31,
	2018			2017			2016
	(in millions)
Cash Flows from Operating Activities:
Net income	$	336		$	433		$	276
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	917			724			838
Amortization of deferred financing costs	11			13			14
Deferred income taxes	(38		)	(98		)	(34		)
Changes in other assets and liabilities:
Accounts and notes receivable, net	11			(73		)	(1		)
Accounts receivable/payable–affiliated companies	20			(46		)	63
Inventory	(16		)	15			(1		)
Accounts payable	(1		)	59			(4		)
Taxes receivable	(5		)	6			53
Interest and taxes accrued	(2		)	7			4
Non-trading derivatives, net	5			—			—
Net regulatory assets and liabilities	(97		)	(148		)	(110		)
Other current assets	(2		)	(6		)	(6		)
Other current liabilities	(26		)	16			21
Other assets	(3		)	13			(8		)
Other liabilities	17			(4		)	(4		)
Other, net	(12		)	(6		)	1
Net cash provided by operating activities	1,115			905			1,102
Cash Flows from Investing Activities:
Capital expenditures	(922		)	(875		)	(862		)
Decrease (increase) in notes receivable–affiliated companies	—			96			(96		)
Other, net	11			3			7
Net cash used in investing activities	(911		)	(776		)	(951		)
Cash Flows from Financing Activities:
Proceeds from long-term debt, net	398			298			600
Payments of long-term debt	(434		)	(411		)	(590		)
Dividend to parent	(209		)	(180		)	(135		)
Increase (decrease) in notes payable–affiliated companies	(59		)	60			(312		)
Debt issuance costs	(4		)	(3		)	(6		)
Contribution from parent	200			—			374
Net cash used in financing activities	(108		)	(236		)	(69		)
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	96			(107		)	82
Cash, Cash Equivalents and Restricted Cash at Beginning of the Year	274			381			299
Cash, Cash Equivalents and Restricted Cash at End of the Year	$	370		$	274		$	381

See Combined Notes to Consolidated Financial Statements

CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC AND SUBSIDIARIES

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

STATEMENTS OF CONSOLIDATED CHANGES IN EQUITY



	2018				2017				2016
	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		1,696				1,696				1,322
Contribution from parent		200				—				374
Balance, end of year		1,896				1,696				1,696
Retained Earnings
Balance, beginning of year		673				420				279
Net income		336				433				276
Dividend to parent		(209		)		(180		)		(135		)
Balance, end of year		800				673				420
Accumulated Other Comprehensive Income (Loss)
Balance, beginning of year		—				1				—
Other comprehensive income (loss)		(14		)		(1		)		1
Balance, end of year		(14		)		—				1
Total Member’s Equity		$	2,682			$	2,369			$	2,117

See Combined Notes to Consolidated Financial Statements

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, 2018 and 2017, 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, 2018, 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, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

February 28, 2019

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

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

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

STATEMENTS OF CONSOLIDATED INCOME



	Year Ended December 31,
	2018			2017			2016
	(in millions)
Revenues:
Utility revenues	$	2,931		$	2,606		$	2,380
Non-utility revenues	4,412			3,997			2,074
Total	7,343			6,603			4,454

Expenses:
Utility natural gas	1,410			1,109			983
Non-utility natural gas	4,364			3,785			1,983
Operation and maintenance	898			816			754
Depreciation and amortization	293			279			249
Taxes other than income taxes	156			147			144
Total	7,121			6,136			4,113
Operating Income	222			467			341

Other Income (Expense):
Interest and other finance charges	(122		)	(123		)	(122		)
Other, net	(8		)	(25		)	(20		)
Total	(130		)	(148		)	(142		)
Income From Continuing Operations Before Income Taxes	92			319			199
Income tax expense (benefit)	22			(265		)	81
Income From Continuing Operations	70			584			118
Income from discontinued operations (net of tax expense of $46, $104, and $81, respectively)	138			161			127
Net Income	$	208		$	745		$	245

See Combined Notes to Consolidated Financial Statements

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

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

STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME



	Year Ended December 31,
	2018			2017			2016
	(in millions)
Net income	$	208		$	745		$	245
Other comprehensive income (loss):
Adjustment to postretirement and other postemployment plans (net of tax expense (benefit) of $1, $4 and ($4))	1			4			(6		)
Net deferred loss from cash flow hedges (net of tax expense (benefit) of $-0-, ($1), and $-0-, respectively)	(1		)	(1		)	—
Other comprehensive income (loss)	—			3			(6		)
Comprehensive income	$	208		$	748		$	239

See Combined Notes to Consolidated Financial Statements

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

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

CONSOLIDATED BALANCE SHEETS



	December 31,
	2018		2017
	(in millions)
ASSETS
Current Assets:
Cash and cash equivalents	$	14	$	12
Accounts receivable, less bad debt reserve of $17 million and $18 million, respectively	894		713
Accrued unbilled revenue	268		307
Accounts and notes receivable — affiliated companies	120		6
Material and supplies	65		56
Natural gas inventory	194		222
Non-trading derivative assets	100		110
Prepaid expenses and other current assets	115		166
Total current assets	1,770		1,592
Property, Plant and Equipment, Net	5,226		4,852
Other Assets:
Goodwill	867		867
Regulatory Assets	181		181
Non-trading derivative assets	38		44
Investment in unconsolidated affiliates - discontinued operations	—		2,472
Other	132		104
Total other assets	1,218		3,668
Total Assets	$	8,214	$	10,112

See Combined Notes to Consolidated Financial Statements

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

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

CONSOLIDATED BALANCE SHEETS, cont.



	December 31,
	2018		2017
	(in millions)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities:
Short-term borrowings	$	—	$	39
Accounts payable	856		669
Accounts and notes payable–affiliated companies	50		611
Taxes accrued	82		75
Interest accrued	38		32
Customer deposits	75		76
Non-trading derivative liabilities	102		20
Other	137		137
Total current liabilities	1,340		1,659

Other Liabilities:
Deferred income taxes, net	406		362
Deferred income taxes, net - discontinued operations	—		927
Non-trading derivative liabilities	5		4
Benefit obligations	93		97
Regulatory liabilities	1,227		1,201
Other	329		297
Total other liabilities	2,060		2,888

Long-Term Debt	2,371		2,457

Commitments and Contingencies (Note 16)

Stockholder’s Equity:
Common stock	—		—
Paid-in capital	2,015		2,528
Retained earnings	423		574
Accumulated other comprehensive income	5		6
Total stockholder’s equity	2,443		3,108

Total Liabilities and Stockholder’s Equity	$	8,214	$	10,112

See Combined Notes to Consolidated Financial Statements

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

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

STATEMENTS OF CONSOLIDATED CASH FLOWS



	Year Ended December 31,
	2018			2017			2016
	(in millions)
Cash Flows from Operating Activities:
Net income	$	208		$	745		$	245
Less: Income from discontinued operations, net of tax	138			161			127
Income from continuing operations	70			584			118
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	293			279			249
Amortization of deferred financing costs	9			9			9
Deferred income taxes	31			(224		)	56
Write-down of natural gas inventory	2			—			1
Changes in other assets and liabilities:
Accounts receivable and unbilled revenues, net	(155		)	(143		)	(122		)
Accounts receivable/payable–affiliated companies	9			—			4
Inventory	17			(22		)	34
Accounts payable	163			64			117
Fuel cost recovery	33			(85		)	(72		)
Interest and taxes accrued	—			(41		)	26
Non-trading derivatives, net	98			(82		)	29
Margin deposits, net	5			(55		)	101
Net regulatory assets and liabilities	50			(27		)	—
Other current assets	4			2			(19		)
Other current liabilities	(3		)	15			2
Other assets	5			(8		)	(21		)
Other liabilities	6			6			(2		)
Other, net	1			6			2
Net cash provided by operating activities from continuing operations	638			278			512
Net cash provided by operating activities from discontinued operations	176			—			—
Net cash provided by operating activities	814			278			512
Cash Flows from Investing Activities:
Capital expenditures	(633		)	(513		)	(517		)
Acquisitions, net of cash acquired	—			(132		)	(102		)
Increase in notes receivable–affiliated companies	(114		)	—			—
Other, net	3			2			1
Net cash used in investing activities from continuing operations	(744		)	(643		)	(618		)
Net cash provided by investing activities from discontinued operations	47			297			660
Net cash provided by (used in) investing activities	(697		)	(346		)	42
Cash Flows from Financing Activities:
Increase (decrease) in short-term borrowings, net	(39		)	4			(5		)
Proceeds from (payments of) commercial paper, net	(688		)	329			350
Proceeds from long-term debt	599			298			—
Payments of long-term debt	—			(550		)	(325		)
Dividends to parent	(360		)	(601		)	(643		)
Debt issuance costs	(5		)	(4		)	—
Loss on reacquired debt	—			(5		)	—
Contribution from parent	960			38			72
Increase (decrease) in notes payable–affiliated companies	(570		)	570			—
Other, net	(1		)	—			(2		)
Net cash provided by (used in) financing activities from continuing operations	(104		)	79			(553		)
Net cash provided by financing activities from discontinued operations	—			—			—
Net cash provided by (used in) financing activities	(104		)	79			(553		)
Net Increase in Cash, Cash Equivalents and Restricted Cash	13			11			1
Cash, Cash Equivalents and Restricted Cash at Beginning of Year	12			1			—
Cash, Cash Equivalents and Restricted Cash at End of Year	$	25		$	12		$	1

See Combined Notes to Consolidated Financial Statements

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

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

STATEMENTS OF CONSOLIDATED CHANGES IN EQUITY



	2018				2017				2016
	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		2,528				2,489				2,417
Contribution from parent		960				38				72
Capital distribution to parent associated with Internal Spin		(1,473		)		—				—
Other		—				1				—
Balance, end of year		2,015				2,528				2,489
Retained Earnings
Balance, beginning of year		574				430				828
Net income		208				745				245
Dividend to parent		(360		)		(601		)		(643		)
Adoption of ASU 2018-02		1				—				—
Balance, end of year		423				574				430
Accumulated Other Comprehensive Income
Balance, beginning of year		6				3				9
Other comprehensive income (loss)		—				3				(6		)
Adoption of ASU 2018-02		(1		)		—				—
Balance, end of year		5				6				3
Total Stockholder’s Equity		$	2,443			$	3,108			$	2,922

See Combined Notes to Consolidated Financial Statements

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

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

General. 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.~~company and owns interests in Enable as described below. As of December 31, 2018, CenterPoint Energy’s operating subsidiaries, ~~own~~Houston Electric and ~~operate~~CERC, owned and operated electric transmission and distribution ~~facilities~~ and natural gas distribution facilities and ~~own interests in Enable Midstream Partners, LP (Enable) as described below. As of~~ ~~December 31, 2015, CenterPoint Energy’s indirect wholly-owned subsidiaries included:~~supplied natural gas to commercial and industrial customers and electric and natural gas utilities.

~~CenterPoint Energy Resources~~CERC Corp. ~~(CERC Corp. and, together with its subsidiaries, CERC), which~~(i) owns and operates natural gas distribution systems ~~(NGD). A wholly-owned subsidiary of CERC Corp.~~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.~~ utilities in over 30 states through its wholly-owned subsidiary, CES.

On April 21, 2018, CenterPoint Energy entered into the Merger Agreement to acquire Vectren for approximately $6 billion in cash. On February 1, 2019, pursuant to the Merger Agreement, CenterPoint Energy consummated the previously announced Merger and acquired Vectren. For further information about the closing of the Merger, see Note 4.

For a description of CenterPoint Energy’s and CERC’s reportable ~~business~~ segments, see Note ~~17.~~19. Houston Electric consists of a single reportable segment, Electric Transmission & Distribution.

(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 ~~CenterPoint Energy~~the Registrants and ~~its~~their wholly-owned and ~~majority owned~~majority-owned subsidiaries are included in the consolidated financial statements. All intercompany transactions and balances are eliminated in consolidation.

As of December 31, 2018, 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 and CERC)

CenterPoint Energy and CERC generally ~~uses~~use the equity method of accounting for investments in entities in which ~~CenterPoint Energy has~~they have an ownership interest between 20% and 50% and ~~exercises~~exercise significant influence. CenterPoint Energy and CERC also ~~uses~~use the equity method for investments in which ~~it has~~they have ownership percentages greater than 50%, when ~~it exercises~~they exercise significant influence, ~~does~~do not have control and isare not considered the primary beneficiary, if applicable.

In May 2013, CenterPoint Energy, OGE Energy Corp. (OGE) and affiliates of ArcLight Capital Partners, LLC (ArcLight), formed Enable as a private limited partnership. CenterPoint Energy has the ability to significantly influence the operating and financial policies of, but not solely control, Enable and, accordingly, recorded an equity method investment, at the historical costs of net assets contributed.

Under the equity method, CenterPoint Energy ~~adjusts its investment in Enable~~and CERC adjust their investments each period for contributions made, distributions received, ~~CenterPoint Energy’s share~~respective shares of ~~Enable’s~~ comprehensive income and amortization of basis differences, as appropriate. CenterPoint Energy ~~evaluates its~~and CERC evaluate their equity method investments for impairment when events or changes in circumstances indicate there is a loss in value of the investment that is other than a temporary decline.

CenterPoint ~~Energy’s~~Energy and CERC consider 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 classify these distributions as operating activities in their respective Statements of Consolidated Cash Flows. CenterPoint Energy and CERC consider 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 classify these distributions as investing activities in their respective Statements of Consolidated Cash Flows.

On September 4, 2018, CERC completed the Internal Spin of its equity investment in Enable ~~is considered to be a variable interest entity (VIE) because~~and Enable GP. For further information regarding 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, 2015, CERC Corp. and OGE held approximately 55.4% and 26.3%, respectively, of the limited partner interests in Enable. Enable is controlled jointly by CERC Corp. and OGE, and each own 50% of the management rights in the general partner of Enable.

As of December 31, 2015, CERC Corp. and OGE also own 40% and 60%, respectively, of the incentive distribution rights held by the general partner of Enable. Enable is expected to pay a minimum quarterly distribution of $0.2875 per unit on its outstanding units to the extent it has sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to its general partner and its affiliates, within 45 days after the end of each quarter. If cash distributions to Enable’s unitholders exceed $0.330625 per unit in any quarter, the general partner will receive increasing percentages or incentive distributions rights, up to 50%, of the cash Enable distributes in excess of that amount. In certain circumstances the general partner of Enable will have the right to reset the minimum quarterly distribution and the target distribution levels at which the incentive distributions receive increasing percentages to higher levels based on Enable’s cash distributions at the time of the exercise of this reset election.

~~Other investments, excluding marketable securities, are carried at cost.~~Internal Spin, see Note 11.

AsInvestments without a readily determinable fair value will be measured at cost, less impairment, plus or minus observable prices changes of ~~December 31, 2015~~, CenterPoint Energy had VIEs consisting of transition and system restoration bond companies, which it consolidates. The consolidated VIEs are wholly-owned bankruptcy remote special purpose entities that were formed specifically for the purpose of securitizing transition and system restoration related property. Creditors of CenterPoint Energy have no recourse to any assetsan identical or ~~revenues~~similar investment of the transition and system restoration 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.same issuer.


~~(c)~~(d)	Revenues

~~CenterPoint Energy records~~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 ~~advanced metering system~~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. For further discussion, see Note 5.

~~(d)~~(e) Long-lived Assets and Intangibles Subject to Amortization

~~CenterPoint Energy records~~The Registrants record property, plant and equipment at historical ~~cost. CenterPoint Energy expenses~~cost and expense repair and maintenance costs as incurred.

~~CenterPoint Energy~~The Registrants periodically ~~evaluates~~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. The determination of whether an impairment has occurred is based on an estimate of undiscounted cash flows attributable to the assets compared to the carrying value of the assets.

~~(e)~~(f) Regulatory Assets and Liabilities

~~CenterPoint Energy applies~~The Registrants apply the guidance for accounting for regulated operations to the Electric Transmission & Distribution ~~business~~reportable segment and the Natural Gas Distribution ~~business~~reportable segment. ~~CenterPoint Energy’s~~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.

~~CenterPoint Energy’s~~The Registrants’ rate-regulated businesses recognize removal costs as a component of depreciation expense in accordance with regulatory treatment. ~~As of~~ ~~December 31, 2015~~ ~~and~~ ~~2014, these removal costs of~~ ~~$980 million~~ ~~and $958 million, respectively, are classified as regulatory liabilities in CenterPoint Energy’s Consolidated Balance Sheets.~~ In addition, a portion of the amount of removal costs collected from customers that relate to ~~asset retirement obligations~~AROs has been reclassified from a regulatory liability to an asset retirement liability in accordance with accounting guidance for ~~asset retirement obligations.~~AROs.

~~(f)~~For further detail on the Registrants’ regulatory assets and liabilities, see Note 7.

(g) Depreciation and Amortization Expense

~~Depreciation~~The Registrants compute depreciation and amortization ~~is computed~~ using the straight-line method based on economic lives or regulatory-mandated recovery periods. Amortization expense includes amortization of certain regulatory assets and other intangibles.

~~(g)~~(h) Capitalization of Interest and ~~Allowance for Funds Used During Construction~~AFUDC

~~Interest~~The Registrants capitalize interest and ~~allowance for funds used during construction (AFUDC) are capitalized~~AFUDC as a component of projects under construction and ~~are amortized~~amortize 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. ~~During~~ ~~2015~~, ~~2014~~Although AFUDC increases both utility plant and ~~2013, CenterPoint Energy capitalized interest and AFUDC of~~ ~~$10 million~~, ~~$11 million~~ ~~and~~ ~~$11 million, respectively. During~~ ~~2015~~, ~~2014~~ ~~and~~ ~~2013, CenterPoint Energy recorded AFUDC equity of $12 million, $14 million and $8 million, respectively, which~~earnings, it is realized in cash when the assets are included in ~~Other Income in its Statements of Consolidated Income.~~rates.



	Year Ended December 31,
	2018						2017						2016
	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric			CERC
	(in millions)
Interest and AFUDC debt (1)	$	8	$	6	$	2	$	9	$	6	$	2	$	8	$	6		$	2
AFUDC equity (2)	12		10		2		11		10		1		7		6		��	1


(1)	Included in Interest and other finance charges on the Registrants’ respective Statements of Consolidated Income.

~~(h)~~


(2)	Included in Other Income (Expense) on the Registrants’ respective Statements of Consolidated Income.

(i) Income Taxes

Houston Electric and CERC are included in CenterPoint ~~Energy uses~~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 bases. A valuation allowance is established against deferred tax assets for which management believes realization is not considered to be more likely than not. ~~CenterPoint Energy recognizes~~The Registrants recognize interest and penalties as a component of income tax ~~expense.~~expense (benefit), as applicable, in their respective Statements of Consolidated Income. CenterPoint Energy reports the income tax provision associated with its interest in Enable in income tax expense (benefit) in its Statements of Consolidated Income.

~~(i)~~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.

(j) Accounts Receivable and Allowance for Doubtful Accounts

Accounts receivable are recorded at the invoiced amount and do not bear interest. ~~It is the policy of management to review~~Management reviews the outstanding accounts receivable, ~~monthly,~~ as well as the bad debt write-offs experienced in the past, and ~~establish~~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 ~~in CenterPoint Energy’s Statements of Consolidated Income~~ for ~~2015~~, ~~2014~~2018, 2017 and ~~2013~~ ~~was~~ ~~$19 million~~, ~~$22 million~~ ~~and~~ ~~$21 million, respectively.~~2016:



	Year Ended December 31,
	2018						2017						2016
	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC
	(in millions)
Provision for doubtful accounts	$	16	$	—	$	16	$	14	$	1	$	13	$	7	$	—	$	7

~~(j)~~(k) Inventory

~~Inventory~~The Registrants’ inventory consists principally of materials and supplies and, for CERC, natural gas. 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 ~~CenterPoint Energy’s~~CERC’s Energy Services business 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. ~~Natural gas inventories of CenterPoint Energy’s Natural Gas Distribution business segment are primarily valued at weighted average cost.~~ During ~~2015~~2018, ~~2014~~2017 and ~~2013~~2016, ~~CenterPoint Energy~~CERC recorded~~$4 million, $8 million and $4 million, respectively, in~~ write-downs of natural gas inventory to the lower of average cost or ~~market.~~market which are disclosed on the respective Statements of Consolidated Cash Flows.

December 31,
2015 2014
(in millions)
Materials and supplies $ 179
$ 168
Natural gas 168
211
Total inventory $ 347
$ 379

~~(k)~~(l) Derivative Instruments

~~CenterPoint Energy is~~The Registrants are exposed to various market risks. These risks arise from transactions entered into in the normal course of business. ~~CenterPoint Energy utilizes~~The Registrants utilize derivative instruments such as physical forward contracts, swaps and options to mitigate the impact of changes in commodity prices, weather and ~~weather~~interest rates on ~~its~~ operating results and cash flows. Such derivatives are recognized in ~~CenterPoint Energy’s~~the Registrants’ Consolidated Balance Sheets at their fair value unless ~~CenterPoint Energy~~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 has a Risk Oversight Committee composed of corporate and ~~business~~reportable segment officers that oversees commodity price, weather and credit risk activities, including ~~CenterPoint Energy’s~~the Registrants’ marketing, risk management services and hedging activities. The committee’s duties are to establish ~~CenterPoint Energy’s~~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 ~~CenterPoint Energy’s~~the Registrants’ risk management policies and procedures and limits established by CenterPoint Energy’s ~~board~~Board of ~~directors.~~Directors.

~~CenterPoint Energy’s~~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.

~~(l)~~(m) Investments in ~~Other Debt~~Equity Securities (CenterPoint Energy and ~~Equity Securities~~CERC)

CenterPoint Energy ~~reports~~and CERC report equity securities ~~classified as trading~~ at estimated fair value in ~~its~~their respective Consolidated Balance Sheets, and any unrealized holding gains and losses are recorded as ~~other income (expense)~~Other Income (Expense) in ~~its~~their respective Statements of Consolidated Income.

~~(m)~~(n) Environmental Costs

~~CenterPoint Energy expenses~~The Registrants expense or ~~capitalizes~~capitalize environmental expenditures, as appropriate, depending on their future economic benefit. ~~CenterPoint Energy expenses~~The Registrants expense amounts that relate to an existing condition caused by past operations that do not have future economic benefit. ~~CenterPoint Energy records~~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.

~~(n) Statements of Consolidated~~(o) Cash ~~Flows~~and Cash Equivalents and Restricted Cash

For purposes of reporting cash flows, ~~CenterPoint Energy considers~~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, 2018 and 2017 are reflected on CenterPoint Energy’s and Houston Electric’s Consolidated Balance Sheets.

In connection with the issuance of ~~transition bonds and system restoration bonds,~~Securitization Bonds, CenterPoint Energy ~~was~~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. ~~These~~For more information on restricted cash ~~accounts~~see Note 20.

(p) 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 ~~$35 million~~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 ~~$47 million~~earned during the period on cumulative preferred stock.

(q) 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 ~~December 31, 2015~~ ~~and~~ ~~2014, respectively,~~operations of the acquired business are included in ~~other current assets in CenterPoint Energy’s~~the Registrants’ respective Statements of Consolidated ~~Balance Sheets. Cash and cash equivalents included~~ ~~$264 million~~ ~~and~~ ~~$290 million~~ ~~as of~~ ~~December 31, 2015~~ ~~and~~ ~~2014, respectively, that was held by CenterPoint Energy’s transition and system restoration bond subsidiaries solely to support servicing the transition and system restoration bonds.~~

~~CenterPoint Energy considers distributions received from equity method investments which do not exceed cumulative equity in earnings subsequent to~~Income beginning on the date of ~~investment to be a return on investment and classifies these distributions as operating activities in~~ the 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 the Statements of Consolidated Cash Flows.acquisition.

~~(o)~~(r) New Accounting Pronouncements

In ~~February 2015,~~The following table provides an overview of recently adopted or issued accounting pronouncements applicable to all the ~~Financial Accounting Standards Board (FASB) issued Accounting Standards Update No. 2015-02,~~ ~~Consolidation~~Registrants, unless otherwise noted.



Recently Adopted Accounting Standards
ASU Number and Name	Description	Date of Adoption	Financial Statement Impact upon Adoption
ASU 2014-09- Revenue from Contracts with Customers (Topic 606) and related amendments	This standard provides a comprehensive new revenue recognition model that requires revenue to be recognized in a manner that depicts the transfer of goods or services to a customer at an amount that reflects the consideration expected to be received in exchange for those goods or services. Transition method: modified retrospective	January 1, 2018	Note 5 addresses the disclosure requirements. Adoption of the standard did not result in significant changes to revenue recognition. A substantial amount of the Registrants’ revenues are tariff and/or derivative based, which were not significantly impacted by these ASUs.
ASU 2017-05- Other Income-Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20): Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets	This standard clarifies when and how to apply ASC 610-20, which was issued as part of ASU 2014-09. It amends or supersedes the guidance in ASC 350 and ASC 360 on determining a gain or loss recognized upon the derecognition of nonfinancial assets. This standard also eliminates industry specific guidance, including ASC 360-20 Property, Plant, and Equipment - Real Estate Sales, for the recognition of gains or losses upon the sale of in-substance real estate. Transition method: modified retrospective	January 1, 2018	CenterPoint Energy and CERC elected to apply the practical expedient upon adoption to only evaluate transactions that were not determined to be complete as of the date of adoption. Subsequent to adoption, gains or losses on sales or dilution events in CenterPoint Energy’s investment in Enable may result in gains or losses recognized in earnings.
ASU 2016-01-Financial Instruments-Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities ASU 2018-03-Technical Corrections and Improvements to Financial Instruments-Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities	This standard requires equity investments that do not result in consolidation and are not accounted for under the equity method to be measured at fair value and to recognize any changes in fair value in net income unless the investments qualify for the new practicability exception. It does not change the guidance for classifying and measuring investments in debt securities and loans. It also changes certain disclosure requirements and other aspects related to recognition and measurement of financial assets and financial liabilities. Transition method: cumulative-effect adjustment to beginning retained earnings, and two features prospective	January 1, 2018	The adoption of this standard did not have an impact on the Registrants’ financial position, results of operations or cash flows. The Registrants elected the practicability exception for investments without a readily determinable fair value to be measured at cost. This includes the Enable Series A Preferred Units owned by CenterPoint Energy, which were previously accounted for under the cost method. See Note 11 for further discussion.



Recently Adopted Accounting Standards
ASU Number and Name	Description	Date of Adoption	Financial Statement Impact upon Adoption
ASU 2016-15- Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments	This standard provides clarifying guidance on the classification of certain cash receipts and payments in the statement of cash flows and eliminates the variation in practice related to such classifications. Transition method:retrospective	January 1, 2018	The adoption did not have a material impact on the Registrants’ financial position, results of operations or disclosures. However, CenterPoint Energy’s and Houston Electric’s Statements of Consolidated Cash Flows reflect an increase in investing activities and a corresponding decrease in operating activities of $2 million, $4 million and $8 million for the years ended December 31, 2018, 2017 and 2016, respectively, due to the requirement that cash proceeds from COLI policies be classified as cash inflows from investing activity.
ASU 2016-18- Statement of Cash Flows (Topic 230): Restricted Cash	This standard requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, restricted cash and restricted cash equivalents. As a result, the statement of cash flows will no longer present transfers between cash and cash equivalents and restricted cash and restricted cash equivalents. When cash, cash equivalents, restricted cash and restricted cash equivalents are presented in more than one line item on the balance sheet, the new guidance requires a reconciliation of the totals in the statement of cash flows to the related captions in the balance sheet. Transition method: retrospective	January 1, 2018	The adoption of this standard did not have a material impact on the Registrants’ financial position, results of operations or disclosures. However, the Registrants’ respective Statements of Consolidated Cash Flows are reconciled to cash, cash equivalents and restricted cash, resulting in a decrease in investing activities of $11 million for each of CenterPoint Energy’s and CERC’s respective Statements of Consolidated Cash Flows for the year ended December 31, 2018. In addition, each of CenterPoint Energy and Houston Electric showed a decrease of $4 million and an increase of $5 million in investing activities for the years ended December 31, 2017 and 2016, respectively, in their respective Statements of Consolidated Cash Flows. See Note 20 for further discussion.
ASU 2017-07- Compensation-Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost	This standard requires an employer to report the service cost component of the net periodic pension cost and postretirement benefit cost in the same line item(s) as other employee compensation costs arising from services rendered during the period; all other components will be presented separately from the line item(s) that includes the service cost and outside of any subtotal of operating income. In addition, only the service cost component will be eligible for capitalization in assets. Transition method: retrospective for the presentation of the service cost component and other components; prospective for the capitalization of the service cost component	January 1, 2018	The adoption of this standard did not have a material impact on the Registrants’ financial position, results of operations, cash flows or disclosures; however, it resulted in the increases to operating income and corresponding decreases to other income reported in the table below. Other components of net periodic costs previously capitalized in assets are recorded as regulatory assets by the Registrants’ rate-regulated businesses prospectively from date of adoption.
ASU 2017-12- Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities	This standard, including standards amending this standard, expands an entity’s ability to hedge and account for risk components, reduces the complexity of applying certain aspects of hedge accounting and updates the presentation and disclosure requirements. The guidance eliminates the requirement to separately measure and report hedge ineffectiveness. Transition method: cumulative-effect adjustment for elimination of the separate measurement of ineffectiveness; prospective for presentation and disclosure	July 1, 2018 Applicable January 1, 2018	The adoption of this standard did not have a material impact on the Registrants’ financial position, results of operations or cash flows. As a result of the adoption, the Registrants will no longer recognize ineffectiveness for derivatives designated as cash flow hedges; all changes in fair value will flow through other comprehensive income. As the Registrants did not have existing cash flow hedges as of the initial application date and the adoption date, no cumulative effective adjustment was recorded. Note 9 reflects disclosures modified upon adoption.
ASU 2018-02-Income Statement-Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income	This standard allows a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the TCJA and requires entities to provide certain disclosures regarding stranded tax effects. Transition method: in the period of adoption	October 1, 2018	The adoption of this standard did not impact the Registrants’ results of operations or cash flows. As a result of the adoption, CenterPoint Energy and CERC elected to reclassify a stranded tax benefit of $15 million and $1 million, respectively, primarily related to benefit plans, from accumulated other comprehensive loss and income to Retained earnings on their respective Consolidated Balance Sheets. The reclassification only encompasses the change in the federal corporate income tax rate due to the TCJA.
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.

The table below reflects the impact of adoption of ASU 2017-07 (Compensation—Retirement Benefits (Topic ~~810): Amendments to the Consolidation~~ ~~Analysis~~ ~~(ASU 2015-02). ASU 2015-02 changes the analysis that reporting organizations must perform to evaluate whether they should consolidate certain legal entities, such as limited partnerships.~~ ~~The changes include, among others, modification~~715)) on each of the ~~evaluation~~Registrants’ respective Statements of whether limited partnerships and similar legal entities are variable interest entities (VIEs) or voting interest entities and elimination of the presumption that a general partner should consolidate a limited partnership. ASU 2015-02 does not amend the related party guidance for situations in which power is shared between two or more entities that hold interests in a VIE. ASU 2015~~-02 is effective for~~ ~~fiscal years, and interim periods within those years,~~ ~~beginning after December 15, 2015.~~ ~~CenterPoint Energy does not believe that ASU 2015-02 will have a material impact on its financial position, results of operations, cash flows and disclosures.~~Consolidated Income:



	Year Ended December 31,
	2018						2017						2016
	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC
	(in millions)
Increase to operating income	$	47	$	21	$	11	$	64	$	26	$	23	$	64	$	25	$	23
Decrease to other income	47		21		11		64		26		23		64		25		23



Issued, Not Yet Effective Accounting Standards
ASU Number and Name	Description	Effective Date	Financial Statement Impact upon Adoption
ASU 2016-02- Leases (Topic 842) and related amendments ASU 2018-01- Leases (Topic 842) Land Easement Practical Expedient for Transition to Topic 842 ASU 2018-10 - Codification Improvements to Topic 842, Leases ASU 2018-11- Leases (Topic 842)-Targeted Improvements ASU 2018-20- Leases (Topic 842)-Narrow-Scope Improvements for Lessors	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 ASU 2018-01 allows entities to elect not to assess whether existing land easements that were not previously accounted for in accordance with ASC 840 Leases under ASC 842 Leases when transitioning to the new leasing standard. ASU 2018-10 makes sixteen narrow-scope amendments to ASC 842 Leases. ASU 2018-11 allows entities the transition option to not apply the new lease standards in the comparative financial statements presented in the year of adoption. It also gives lessors the practical expedient to not separate non-lease and lease components when certain criteria are met. ASU 2018-20 updates several narrow-scope changes for lessors, including sales taxes collected from lessees, lessor costs paid directly by lessees, and recognition of variable payments for contracts with lease and non-lease components.	January 1, 2019 Early adoption is permitted	The Registrants have completed the identification of leases under the revised definition. In addition to expanded disclosure for lessees and lessors, which will include qualitative disclosures of the nature of the lease population and additional quantitative information, the Registrants expect to recognize approximately $30 million, $1 million and $28 million of right-of-use assets and lease liabilities on the statements of financial position of CenterPoint Energy, Houston Electric and CERC, respectively, on the date of adoption but do not expect a material impact on their results of operations and cash flows. The Registrants elected the practical expedient for existing easements provided by ASU 2018-01, and the transition option to not apply the new lease standards in the comparative financial statements presented in the year of adoption provided by ASU 2018-11.
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 starting January 1, 2019	The Registrants are currently assessing the impact that this standard will have on their financial position, results of operations, cash flows and disclosures.

~~In April 2015, the FASB issued Accounting Standards Update No. 2015-03,~~ ~~Interest-Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Cost~~ ~~(ASU 2015-03)~~. ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by ASU 2015-03. CenterPoint Energy will adopt ASU 2015-03 retrospectively on January 1, 2016, which will result in a reduction of both other long-term assets and long-term debt on its Consolidated Balance Sheets. CenterPoint Energy had debt issuance costs of $53 million and $61 million included in other long-term assets on its Consolidated Balance Sheets as of December 31, 2015 and 2014, respectively.

Management believes that other recently adopted standards and recently issued standards ~~which~~that are not yet effective will not have a material impact on ~~CenterPoint Energy’s consolidated~~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:


	Weighted Average Useful Lives	December 31,					December 31, 2018						December 31, 2017
	(Years)	2015		2014		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 millions)
CenterPoint Energy						(in years)	(in millions)
Electric Transmission & Distribution	31	$	10,142	$	9,393	35	$	12,148	$	3,746	$	8,402	$	11,496	$	3,633	$	7,863
Natural Gas Distribution	32	5,762		5,235		28	7,257		2,128		5,129		6,735		1,968		4,767
Energy Services	27	86		84		27	121		43		78		102		35		67
Other property	24	660		646		26	741		306		435		698		338		360
Total		16,650		15,358			$	20,267	$	6,223	$	14,044	$	19,031	$	5,974	$	13,057
Accumulated depreciation and amortization:
Electric Transmission & Distribution		3,209		3,050
Houston Electric						Houston Electric
Electric Transmission						45	$	3,077	$	650	$	2,427	$	2,767	$	620	$	2,147
Electric Distribution						33	7,524		2,553		4,971		7,178		2,522		4,656
Other transmission & distribution property						18	1,547		543		1,004		1,551		491		1,060
Total							$	12,148	$	3,746	$	8,402	$	11,496	$	3,633	$	7,863
CERC						CERC
Natural Gas Distribution		1,575		1,493		28	$	7,257	$	2,128	$	5,129	$	6,735	$	1,968	$	4,767
Energy Services		34		31		27	121		43		78		102		35		67
Other property		295		282		23	53		34		19		51		33		18
Total accumulated depreciation and amortization		5,113		4,856
Property, plant and equipment, net		$	11,537	$	10,502
Total							$	7,431	$	2,205	$	5,226	$	6,888	$	2,036	$	4,852

(b) Depreciation and Amortization

The following table presents depreciation and amortization expense for ~~2015~~2018, ~~2014~~2017 and ~~2013~~2016.:

2015 2014 2013
(in millions)
Depreciation expense $ 557
$ 521
$ 531
Amortization expense 413
492
423
Total depreciation and amortization expense $ 970
$ 1,013
$ 954



	Year Ended December 31,
	2018						2017						2016
	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC
	(in millions)
Depreciation	$	626	$	342	$	264	$	619	$	354	$	243	$	607	$	349	$	230
Amortization of securitized regulatory assets	531		531		—		329		329		—		455		455		—
Other amortization	86		44		29		88		41		36		64		34		19
Total	$	1,243	$	917	$	293	$	1,036	$	724	$	279	$	1,126	$	838	$	249

~~A reconciliation of the changes in the asset retirement obligation (ARO) liability is as follows:~~

December 31,
2015 2014
(in millions)
Beginning balance $ 176
$ 134
Accretion expense 6
5
Revisions in estimates of cash flows 13
37
Ending balance $ 195
$ 176

~~CenterPoint Energy~~The Registrants recorded AROs associated with the removal of asbestos and asbestos-containing material in its buildings, including substation building structures. CenterPoint Energy and Houston Electric also recorded AROs relating to ~~gas pipelines abandoned in place,~~ treated wood poles for electric distribution, distribution transformers containing PCB (also known as Polychlorinated Biphenyl), and underground fuel storage tanks. 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.

~~The increase~~A reconciliation of ~~$13 million~~the changes in the ARO ~~from the revision of estimate~~liability recorded in ~~2015 is primarily attributable to an increase in estimated disposal costs. The increase of $37 million in the ARO from the revision of estimate in 2014 is primarily attributable to a reduction~~Other non-current liabilities on each of the ~~estimated service lives of steel and plastic pipe.~~

~~(4)~~ ~~Goodwill~~

~~Goodwill by reportable business segment as of both December 31, 2015 and 2014 are~~Registrants’ respective Consolidated Balance Sheets is as follows:

(in millions)
Natural Gas Distribution $ 746
Energy Services (1) 83
Other 11
Total $ 840



	December 31, 2018									December 31, 2017
	CenterPoint Energy			Houston Electric			CERC			CenterPoint Energy		Houston Electric		CERC
	(in millions)
Beginning balance	$	281		$	35		$	243		$	205	$	33	$	169
Accretion expense (1)	10			1			9			8		1		7
Revisions in estimates (2)	(33		)	(2		)	(31		)	68		1		67
Ending balance	$	258		$	34		$	221		$	281	$	35	$	243


(1)	~~Amounts~~Reflected in Regulatory assets on each of the Registrants’ respective Consolidated Balance Sheets.

(2)

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. In 2017, CenterPoint Energy and CERC 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.

(4) Mergers and Acquisitions

Merger with Vectren (CenterPoint Energy)

On February 1, 2019 (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 therefor 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. See Notes 13 and 14 for further details regarding the Merger financings.

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.

On the Merger Date, Vectren became a wholly-owned subsidiary of CenterPoint Energy. Vectren, through its wholly owned subsidiary, VUHI, holds 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 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 is also involved in non-utility activities through two business units:

Infrastructure Services provides underground pipeline construction and repair services; and

ESG provides energy performance contracting and sustainable infrastructure, such as renewables, distributed generation and combined heat and power projects.

As of December 31, 2018, Vectren and its subsidiaries had outstanding $167 million of short-term debt and $2.2 billion of long-term debt, including current maturities. Vectren’s outstanding short-term and long-term debt on the closing date of the Merger became debt of CenterPoint Energy.

The Merger is anticipated to provide 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 Merger is being accounted for in accordance with ASC 805, Business Combinations, with identifiable assets acquired and liabilities assumed recorded at their estimated fair values on the Merger Date. Due to the limited time between the Merger Date and this filing, CenterPoint Energy’s purchase price allocation for the assets acquired and the liabilities assumed in the Merger has not been completed. CenterPoint Energy will provide the required disclosures in the first quarter of 2019. The results of operations of Vectren will be reported in CenterPoint Energy’s consolidated financial statements beginning on the Merger Date.

CenterPoint Energy incurred transaction costs of $28 million and integration costs of $18 million in connection with the Merger for the year ended December 31, 2018, which were included in operation and maintenance expenses in CenterPoint Energy’s Statements of Consolidated Income.

Acquisition of AEM (CenterPoint Energy and CERC)

On January 3, 2017,CES completed the acquisition of AEM. After working capital adjustments, the final purchase price of $147 million was allocated to identifiable assets acquired and liabilities assumed based on their fair values on the acquisition date.

The goodwill of $5 million recorded as part of the acquisition primarily reflects the value of the complementary operational and geographic footprints, scale and expanded capabilities provided by the acquisition.

The fair value of the identifiable intangible assets and related useful lives included in the final purchase price allocation is as follows:

The following unaudited pro forma financial information reflects the consolidated results of operations of CenterPoint Energy and CERC, assuming the AEM acquisition had taken place on January 1, 2016. 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 acquisition taken place on the dates indicated or the future consolidated results of operations of the combined companies.



	Year Ended December 31,
	2017				2016
	CenterPoint Energy		CERC		CenterPoint Energy		CERC
	(in millions)
Revenues	$	9,614	$	6,603	$	8,541	$	5,467
Net Income (1)	1,792		745		442		255


(1)	Net income for the year ended December 31, 2017 includes a reduction in income tax expense of $1,113 million and $396 million due to the TCJA for CenterPoint Energy and CERC, respectively. See Note 15 for further discussion of the impacts of tax reform implementation.

(5) Revenue Recognition

The Registrants adopted ASC 606 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. Contract assets and liabilities are not material.

The following tables disaggregate revenues by reportable segment and major source:



	Year Ended December 31, 2018
	CenterPoint Energy														Houston Electric			CERC
	Electric Transmission & Distribution (1)			Natural Gas Distribution (1)			Energy Services (2)			Other Operations (2)		Total			Total			Natural Gas Distribution (1)			Energy Services (2)			Other Operations (2)		Total
	(in millions)
Revenue from contracts	$	3,235		$	3,011		$	493		$	6	$	6,745		$	3,235		$	3,011		$	493		$	1	$	3,505
Derivatives income	(2		)	(2		)	4,028			—		4,024			—			(2		)	4,028			—		4,026
Other (3)	(1		)	(42		)	—			9		(34		)	(1		)	(42		)	—			—		(42		)
Eliminations	—			(36		)	(110		)	—		(146		)	—			(36		)	(110		)	—		(146		)
Total revenues	$	3,232		$	2,931		$	4,411		$	15	$	10,589		$	3,234		$	2,931		$	4,411		$	1	$	7,343

	Year Ended December 31, 2017
	CenterPoint Energy														Houston Electric			CERC
	Electric Transmission & Distribution (1)			Natural Gas Distribution (1)			Energy Services (2)			Other Operations (2)		Total			Total			Natural Gas Distribution (1)			Energy Services (2)			Other Operations (2)		Total
	(in millions)
Revenue from contracts	$	3,001		$	2,638		$	480		$	5	$	6,124		$	3,001		$	2,638		$	480		$	—	$	3,118
Derivatives income	(1		)	—			3,569			—		3,568			—			—			3,569			—		3,569
Other (3)	(3		)	1			—			9		7			(3		)	1			—			—		1
Eliminations	—			(33		)	(52		)	—		(85		)	—			(33		)	(52		)	—		(85		)
Total revenues	$	2,997		$	2,606		$	3,997		$	14	$	9,614		$	2,998		$	2,606		$	3,997		$	—	$	6,603

	Year Ended December 31, 2016
	CenterPoint Energy														Houston Electric			CERC
	Electric Transmission & Distribution (1)			Natural Gas Distribution (1)			Energy Services (2)			Other Operations (2)		Total			Total			Natural Gas Distribution (1)			Energy Services (2)			Other Operations (2)		Total
	(in millions)
Revenue from contracts	$	3,050		$	2,368		$	288		$	5	$	5,711		$	3,050		$	2,368		$	288		$	—	$	2,656
Derivatives income	1			—			1,811			—		1,812			—			—			1,811			—		1,811
Other (3)	9			41			—			10		60			9			41			—			1		42
Eliminations	—			(29		)	(26		)	—		(55		)	—			(29		)	(26		)	—		(55		)
Total revenues	$	3,060		$	2,380		$	2,073		$	15	$	7,528		$	3,059		$	2,380		$	2,073		$	1	$	4,454


(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

Electric Transmission & Distribution. 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.

Natural Gas Distribution. 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. 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.

Practical Expedients and Exemption. Sales taxes and other similar taxes collected from customers are excluded from the transaction price.

(6) Goodwill and Other Intangibles (CenterPoint Energy and CERC)

CenterPoint Energy’s and CERC’s goodwill by reportable segment as of both December 31, 2018 and 2017 is as follows:



	(in millions)
Natural Gas Distribution	$	746
Energy Services (1)	110
Other Operations	11
Total	$	867


(1)	Amount presented ~~are~~is net of the accumulated goodwill impairment charge of $252 ~~million.~~million recorded in 2012.

CenterPoint Energy ~~performs~~and CERC perform goodwill impairment tests at least annually and ~~evaluates~~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 ~~using a two-step process. In the first step,~~comparing the fair value of each reporting unit ~~is compared~~ with the carrying amount of the reporting unit, including goodwill. The estimated fair value of the reporting unit is ~~generally~~primarily determined on the basis of discounted cash flows. If the carrying amount is in excess of the estimated fair value of the reporting unit, then the excess amount is ~~less than~~the impairment charge that should be recorded, not to exceed the carrying amount of the reporting unit, then a second step must be completed to determine the amount of the goodwill impairment that should be recorded. In the second step, the implied fair value of the reporting unit’s goodwill is determined by allocating the reporting unit’s fair value to all of its assets and liabilities other than goodwill (including any unrecognized intangible assets) in a manner similar to a purchase price allocation. The resulting implied fair value of the goodwill that results from the application of this second step is then compared to the carrying amount of the goodwill and an impairment charge is recordedgoodwill. See Note 2(e) for ~~the difference.~~

further discussion.

CenterPoint Energy and CERC performed ~~its~~the annual goodwill impairment test in the third quarter of each of ~~2015~~2018 and ~~2014~~2017 and determined ~~based on the results of the first step,~~ that no goodwill impairment charge was required for any reporting unit, which approximate the Registrants’ applicable reportable ~~segment.~~segments.

The tables below present information on CenterPoint Energy’s and CERC’s finite lived intangible assets recorded in Other ~~intangibles were not material~~non-current assets on the Consolidated Balance Sheets. Finite lived intangible assets are amortized over their estimated useful lives.



	December 31, 2018							December 31, 2017
	Gross Carrying Amount		Accumulated Amortization			Net Balance		Gross Carrying Amount		Accumulated Amortization			Net Balance
	(in millions)
Customer relationships	$	86	$	(27	)	$	59	$	86	$	(21	)	$	65
Covenants not to compete	4		(3		)	1		4		(2		)	2
Other	16		(11		)	5		15		(8		)	7
Total	$	106	$	(41	)	$	65	$	105	$	(31	)	$	74



	Year Ended December 31,
	2018		2017		2016
	(in millions)
Amortization expense of intangible assets (1)	$	10	$	13	$	4


(1)	Recorded in Depreciation and amortization expenses on CenterPoint Energy’s and CERC’s respective Statements of Consolidated Income.

CenterPoint Energy and CERC estimate that amortization expense of intangible assets with finite lives for the next five years will be as ~~of December 31, 2015 and 2014.~~follows:



	Amortization Expense
	(in millions)
2019	$	11
2020	6
2021	6
2022	6
2023	5

~~(5)~~(7) Regulatory Accounting

The following is a list of regulatory ~~assets/~~assets and liabilities reflected on ~~CenterPoint Energy’s~~the Registrants’ respective Consolidated Balance Sheets as of December 31, ~~2015~~2018 and ~~2014~~2017:


	December 31,						December 31, 2018									December 31, 2017
	2015			2014			CenterPoint Energy			Houston Electric			CERC			CenterPoint Energy				Houston Electric			CERC
	(in millions)						(in millions)
Regulatory Assets:
Current regulatory assets (1)							$	77		$	—		$	77		$	130		��	$	—		$	130
Non-current regulatory assets:
Securitized regulatory assets	$	2,373		$	2,738		1,059			1,059			—			1,590				1,590			—
Unrecognized equity return (1)	(393		)	(442		)
Unrecognized equity return (2)							(213		)	(213		)	—			(287		)		(287		)	—
Unamortized loss on reacquired debt	93			104			68			68			—			75				75			—
Pension and postretirement-related regulatory asset (2)	872			922
Other long-term regulatory assets (3)	184			205
Pension and postretirement-related regulatory asset (3)							725			33			30			646				31			20
Hurricane Harvey restoration costs (4)							68			64			4			64				58			6
Regulatory assets related to TCJA (5)							33			23			10			48				33			15
Other long-term regulatory assets (6)							227			90			137			211				70			140
Total non-current regulatory assets							1,967			1,124			181			2,347				1,570			181
Total regulatory assets	3,129			3,527			2,044			1,124			258			2,477				1,570			311

Regulatory Liabilities:
Current regulatory liabilities (7)							38			17			21			24				22			2
Non-current regulatory liabilities:
Regulatory liabilities related to TCJA (5)							1,323			847			476			1,354				862			492
Estimated removal costs	980			958			886			269			617			878				285			593
Other long-term regulatory liabilities	296			248			316			182			134			232				116			116
Total non-current regulatory liabilities							2,525			1,298			1,227			2,464				1,263			1,201
Total regulatory liabilities	1,276			1,206			2,563			1,315			1,248			2,488				1,285			1,203

Total regulatory assets and liabilities, net	$	1,853		$	2,321		$	(519	)	$	(191	)	$	(990	)	$	(11	)		$	285		$	(892	)


(1)	Current regulatory assets are included in Prepaid expenses and other current assets in the Registrants’ respective Consolidated Balance Sheets.

(2)

~~As of~~ ~~December 31, 2015, CenterPoint Energy has not recognized an allowed~~The unrecognized equity ~~return of~~ ~~$393 million~~ ~~because such~~ return will be recognized as it is recovered in rates through 2024. During the years ended December 31, ~~2015~~2018, ~~2014~~2017 and ~~2013~~2016, ~~CenterPoint~~ Houston Electric recognized approximately $4974 million, $6842 million and $4564 million, respectively, of the allowed equity return. The timing of ~~CenterPoint Energy’s~~Houston Electric’s recognition of the ~~allowed~~ equity return will vary each period based on amounts actually collected during the period. The actual amounts ~~recovered for the allowed equity return~~recognized are ~~reviewed and~~ adjusted at least annually ~~by the Texas Utility Commission~~ to correct any over-collections or under-collections during the preceding 12 ~~months and to provide for the full and timely recovery of the allowed equity return.~~months.

~~(2)~~(3)

Includes a portion of Houston Electric’s and CERC’s NGD’s actuarially determined pension and other postemployment expense in excess of the amount being recovered through rates that is being deferred for rate making ~~purposes. Deferred pension~~purposes, of which $33 million and ~~other postemployment expenses of $5~~$4 million as of December 31, ~~2015~~2018, respectively, and $31 million and $7 million as of December 31, 2017, respectively, were not earning a return.

~~(3)~~(4)

The Registrants suffered damage as a result of Hurricane Harvey, a major storm classified as a Category 4 hurricane on the Saffir-Simpson Hurricane Wind Scale, that first struck the Texas coast on Friday, August 25, 2017 and remained over the Houston area for the next several days. The unprecedented flooding from torrential amounts of rainfall accompanying the storm caused significant damage to or destruction of residences and businesses served by the Registrants. The Registrants deferred the uninsured storm restoration costs as management believed it was probable that such costs will be recovered through traditional rate adjustment mechanisms for capital costs and through the next base rate proceeding for operation and maintenance expenses. As a result, storm restoration costs did not materially affect the Registrants’ reported net income for 2017. The Registrants are not earning a return on Hurricane Harvey restoration costs.


(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)	Other long-term regulatory assets that are not earning a return were not material as of December 31, ~~2015~~2018 and ~~2014~~2017.


(7)	Current regulatory liabilities are included in Other current liabilities in each of the Registrants’ respective Consolidated Balance Sheets.

~~(6)~~ (8) Stock-Based Incentive Compensation Plans and Employee Benefit Plans

(a) Stock-Based Incentive Compensation Plans (CenterPoint Energy)

CenterPoint Energy has ~~long-term incentive plans (LTIPs)~~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 ~~CenterPoint Energy common stock~~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. ~~The performance awards granted in~~ ~~2015~~, ~~2014~~ ~~and~~ ~~2013~~ ~~are distributed based upon the achievement of certain objectives over a three-year performance cycle. The stock awards granted in~~ ~~2015~~ ~~and 2014 are service based. The stock awards granted in~~ ~~2013~~ ~~are subject to the performance condition that total common dividends declared during the~~ ~~three-year vesting period must be at least~~ ~~$2.49~~ per share. The stock awards generally vest at the end of a three-year period. Upon vesting, both the performance and stock awards are issued to the participants along with the value of dividend equivalents earned over the performance cycle or vesting period. CenterPoint Energy issues new shares in order to satisfy stock-based payments related to LTIPs.

~~CenterPoint Energy recorded LTIP compensation expense of~~ ~~$17 million~~, ~~$18 million~~ ~~and~~ ~~$19 million~~ ~~for the years ended~~ ~~December 31, 2015~~, ~~2014~~ ~~and~~ ~~2013, respectively. This expense is included in Operation and Maintenance Expense in the Statements of Consolidated Income.~~

~~The total income tax benefit recognized related to LTIPs was~~ ~~$6 million, $7 million and $7 million for the years ended~~ ~~December 31, 2015~~, ~~2014~~ ~~and~~ ~~2013, respectively.~~ No ~~compensation cost related to LTIPs was capitalized as a part of inventory or fixed assets in~~ ~~2015~~, ~~2014~~ or ~~2013. The actual tax benefit realized for tax deductions related to LTIPs totaled~~ ~~$6 million~~, ~~$13 million~~ ~~and~~ ~~$13 million~~ ~~for~~ ~~2015~~, ~~2014~~ ~~and~~ ~~2013, respectively.~~

Compensation costs for the performance and stock 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~~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 2018, 2017 and 2016 are distributed based upon the achievement of certain objectives over a three-year performance cycle. The stock unit awards granted in 2018, 2017 and 2016 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 and 2016) or vested immediately upon grant (for awards granted in 2018). Upon vesting, both the performance and stock awards are issued to the participants along with the value of dividend equivalents earned over the performance cycle or vesting period.

The following table summarizes CenterPoint Energy’s expenses related to LTIPs for 2018, 2017 and 2016:



	Year Ended December 31,
	2018		2017		2016
	(in millions)
LTIP Compensation expense (1)	$	26	$	21	$	19
Income tax benefit recognized	6		8		7
Actual tax benefit realized for tax deductions	5		6		5


(1)	Included in Operation and maintenance expense in CenterPoint Energy’s Statements of Consolidated Income and not capitalized as a part of Inventory or Property, Plant and Equipment.

The following tables summarize CenterPoint Energy’s LTIP activity for ~~2015~~2018:



	Year Ended December 31, 2018
	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, 2017	3,627		$	22.15
Granted	1,321		26.74
Forfeited or canceled	(721	)	21.72
Vested and released to participants	(409	)	21.31
Outstanding and non-vested as of December 31, 2018	3,818		$	23.91	1	$	57

Stock Awards
Outstanding and non-vested as of December 31, 2017	980		$	22.68
Granted	409		26.62
Forfeited or canceled	(29	)	25.31
Vested and released to participants	(300	)	22.84
Outstanding and non-vested as of December 31, 2018	1,060		$	24.08	1.1	$	30


(1)	Reflects maximum performance achievement.

~~Stock Options~~


(2)	Reflects the impact of current expectations of achievement and stock price.

~~CenterPoint Energy has not issued stock options since 2004. There were no outstanding stock options at either December 31, 2015 or 2014.~~

~~Cash received from stock options exercised was~~ ~~$1 million~~ ~~and~~ ~~$3 million~~ ~~for~~ ~~2014~~ ~~and~~ ~~2013, respectively.~~

~~Performance Awards~~

Outstanding and Non-Vested Shares
Year Ended December 31, 2015

Shares
(Thousands)

Weighted-Average
Grant Date
Fair Value

Remaining Average
Contractual
Life (Years)

Aggregate
Intrinsic
Value (Millions)
Outstanding as of December 31, 2014 2,460
$ 21.26

Granted 1,158
21.28

Forfeited or canceled (592 ) 19.89

Vested and released to participants (398 ) 18.79

Outstanding as of December 31, 2015 2,628
21.95
1.2 $ 28

The outstanding and non-vested shares displayed in the table above assumes that shares are issued at the maximum performance level. The aggregate intrinsic value reflects the impact of current expectations of achievement and stock price.

~~Stock Awards~~

Outstanding and Non-Vested Shares
Year Ended December 31, 2015

Shares
(Thousands)

Weighted-Average
Grant Date
Fair Value

Remaining Average
Contractual
Life (Years)

Aggregate
Intrinsic
Value (Millions)
Outstanding as of December 31, 2014 723
$ 21.41

Granted 376
21.39

Forfeited or canceled (53 ) 22.40

Vested and released to participants (299 ) 20.08

Outstanding as of December 31, 2015 747
21.86
1.1 $ 14

~~The weighted-average grant-date~~weighted average grant date fair values per unit of awards granted were as follows for ~~2015~~, ~~2014~~2018, 2017 and ~~2013~~:2016:

Year Ended December 31,
2015 2014 2013
Performance awards $ 21.28
$ 23.70
$ 20.67
Stock awards 21.39
23.89
21.53



	Year Ended December 31,
	2018		2017		2016
	(In millions, except for per unit amounts)
Performance Awards
Weighted-average grant date fair value per unit of awards granted	$	26.74	$	26.64	$	18.98
Total intrinsic value of awards received by participants	12		7		7
Vested grant date fair value	9		5		7

Stock Awards
Weighted-average grant date fair value per unit of awards granted	$	26.62	$	26.77	$	19.24
Total intrinsic value of awards received by participants	9		9		6
Vested grant date fair value	7		7		6

~~Valuation Data~~

~~The total intrinsic value~~As of ~~awards received by participants was as follows for~~ ~~2015~~, ~~2014~~ ~~and~~ ~~2013~~:

Year Ended December 31,
2015 2014 2013
(in millions)
Stock options exercised $ —
$ 2
$ 4
Performance awards 9
24
20
Stock awards 7
10
10

~~The total grant date fair value of performance and stock awards which vested during the years ended~~ December 31, ~~2015~~, ~~2014~~ ~~and~~ ~~2013~~ ~~was~~ ~~$13 million~~, ~~$21 million~~ ~~and~~ ~~$19 million, respectively. As of~~ ~~December 31, 2015~~,2018, there was $1827 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 ~~1.6~~1.7 years.

(b) Pension ~~and Postretirement~~ Benefits (CenterPoint Energy)

CenterPoint Energy maintains a non-contributory qualified defined benefit pension plan covering substantially all employees, with benefits determined using a cash balance formula. Substantially all of the Registrants’ employees participate in CenterPoint Energy’s non-contributory qualified defined benefit plan. Under the cash balance formula, participants accumulate a retirement

benefit based upon 5% of eligible earnings and accrued interest. Participants are 100% vested in their benefit after completing three years of service. In addition to the non-contributory qualified defined benefit pension ~~plan,~~plans, CenterPoint Energy maintains unfunded non-qualified benefit restoration plans which allow participants to receive the benefits to which they would have been entitled under CenterPoint Energy’s non-contributory qualified pension plan except for federally mandated limits on qualified plan benefits or on the level of compensation on which qualified plan benefits may be calculated.

CenterPoint Energy provides certain healthcare and life insurance benefits for retired employees on both a contributory and non-contributory basis. Employees become eligible for these benefits if they have met certain age and service requirements at retirement, as defined in the plans. Under plan amendments, effective in early 1999, healthcare benefits for future retirees were changed to limit employer contributions for medical coverage.

~~Such benefit costs are accrued over the active service period of employees. The net unrecognized transition obligation is being amortized over approximately~~ ~~20 years~~.

CenterPoint Energy’s net periodic cost includes the following components relating to pension, including the non-qualified benefit restoration ~~plan, and postretirement benefits:~~plan:

Year Ended December 31,
2015 2014 2013
Pension
Benefits Post-retirement
Benefits
Pension
Benefits

Post-retirement
Benefits

Pension
Benefits

Post-retirement
Benefits
(in millions)
Service cost $ 41
$ 2
$ 42
$ 2
$ 44
$ 2
Interest cost 93
20
100
22
90
20
Expected return on plan assets (120 ) (7 ) (125 ) (7 ) (135 ) (7 )
Amortization of prior service cost (credit) 9
(1 ) 10
(1 ) 10
1
Amortization of net loss 57
5
44
1
63
6
Amortization of transition obligation —
—
—
5
—
7
Curtailment (1) —
—
6
—
—
—
Settlement (2) 10
—
—
—
—
—
Net periodic cost $ 90
$ 19
$ 77
$ 22
$ 72
$ 29



	Year Ended December 31,
	2018			2017			2016
	(in millions)
Service cost (1)	$	37		$	36		$	38
Interest cost (2)	79			89			93
Expected return on plan assets (2)	(107		)	(97		)	(101		)
Amortization of prior service cost (2)	9			9			9
Amortization of net loss (2)	43			58			63
Net periodic cost	$	61		$	95		$	102

(1)

~~During~~Amounts presented in the ~~fourth quarter~~table above are included in Operation and maintenance expense in CenterPoint Energy’s Statements of ~~2014, CenterPoint Energy recognized a curtailment pension loss~~Consolidated Income, net of ~~$6 million related to employees seconded to Enable. Substantially all of the seconded employees became employees of Enable effective January 1, 2015.~~regulatory deferrals and amounts capitalized. See Note 2(r).

(2)

~~A one-time, non-cash settlement charge is required when lump sum distributions or other settlements~~Amounts presented in the table above are included in Other, net in CenterPoint Energy’s Statements of ~~plan benefit obligations during a plan year exceed the service cost and interest cost components~~Consolidated Income, net of net periodic cost for that year. Due to the amount of lump sum payment distributions from the non-qualified pension plan during the year ended December 31, 2015, CenterPoint Energy recognized a non-cash settlement charge of $10 million. This charge is an acceleration of costs that would otherwise be recognized in future periods. regulatory deferrals. See Note 2(r).

CenterPoint Energy used the following assumptions to determine net periodic cost relating to pension ~~and postretirement~~ benefits:


	Year Ended December 31,
	2015				2014				2013				Year Ended December 31,
	Pension Benefits		Post-retirement Benefits		Pension Benefits		Post-retirement Benefits		Pension Benefits		Post-retirement Benefits		2018		2017		2016
Discount rate	4.05	%	3.90	%	4.80	%	4.75	%	4.00	%	3.90	%	3.65	%	4.15	%	4.40	%
Expected return on plan assets	6.50		5.20		7.00		5.50		8.00		5.50		6.00		6.00		6.25
Rate of increase in compensation levels	4.00		—		3.90		—		4.00		—		4.45		4.50		4.15

In determining net periodic ~~benefits~~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 ~~consolidated balance sheets and~~the Consolidated Balance Sheets as well as the key assumptions of CenterPoint Energy’s pension ~~including benefit restoration, and postretirement~~ plans. The measurement dates for plan assets and obligations were December 31, ~~2015~~2018 and ~~2014~~.2017.

December 31,
2015 2014
Pension
Benefits Post-retirement
Benefits
Pension
Benefits

Post-retirement
Benefits
(in millions, except for actuarial assumptions)
Change in Benefit Obligation
Benefit obligation, beginning of year $ 2,403
$ 529
$ 2,153
$ 476
Service cost 41
2
42
2
Interest cost 93
20
100
22
Participant contributions —
8
—
7
Benefits paid (234 ) (32 ) (156 ) (32 )
Actuarial (gain) loss (115 ) (87 ) 264
52
Medicare reimbursement —
2
—
3
Plan amendment —
(10 ) —
1
Settlement 5
—
—
—
Curtailment —
—
—
(2 )
Benefit obligation, end of year 2,193
432
2,403
529
Change in Plan Assets

Fair value of plan assets, beginning of year 1,925
141
1,803
140
Employer contributions 66
18
97
18
Participant contributions —
8
—
7
Benefits paid (234 ) (32 ) (156 ) (32 )
Actual investment return (loss) (78 ) 1
181
8
Fair value of plan assets, end of year 1,679
136
1,925
141
Funded status, end of year $ (514 ) $ (296 ) $ (478 ) $ (388 )
Amounts Recognized in Balance Sheets

Current liabilities-other $ (8 ) $ (8 ) $ (31 ) $ (9 )
Other liabilities-benefit obligations (506 ) (288 ) (447 ) (379 )
Net liability, end of year $ (514 ) $ (296 ) $ (478 ) $ (388 )
Actuarial Assumptions

Discount rate 4.40 % 4.35 % 4.05 % 3.90 %
Expected return on plan assets 6.25
4.80
6.50
5.20
Rate of increase in compensation levels 4.15
—
4.00
—
Healthcare cost trend rate assumed for the next year - Pre-65 —
6.00
—
7.25
Healthcare cost trend rate assumed for the next year - Post-65 —
5.50
—
8.50
Prescription drug cost trend rate assumed for the next year —
11.00
—
6.50
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate) —
5.00
—
5.00
Year that the healthcare rate reaches the ultimate trend rate —
2024
—
2024
Year that the prescription drug rate reaches the ultimate trend rate —
2024
—
2024

~~The accumulated benefit obligation for all defined benefit pension plans was~~ ~~$2,157 million~~ ~~and~~ ~~$2,371 million~~ ~~as of~~ ~~December 31, 2015~~ ~~and~~ ~~2014, respectively.~~

~~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.~~



	December 31,
	2018			2017
	(in millions, except for actuarial assumptions)
Change in Benefit Obligation
Benefit obligation, beginning of year	$	2,225		$	2,197
Service cost	37			36
Interest cost	79			89
Benefits paid	(201		)	(168		)
Actuarial (gain) loss (1)	(127		)	71
Benefit obligation, end of year	2,013			2,225
Change in Plan Assets
Fair value of plan assets, beginning of year	1,801			1,656
Employer contributions	69			48
Benefits paid	(201		)	(168		)
Actual investment return	(153		)	265
Fair value of plan assets, end of year	1,516			1,801
Funded status, end of year	$	(497	)	$	(424	)

The discount rate assumption was determined by matching the projected cash flows of CenterPoint Energy’s plans against a hypothetical yield curve of high-quality corporate bonds represented by a series of annualized individual discount rates from one-half to 99 years.

~~For measurement purposes, medical costs are assumed to increase~~ ~~6.00%~~ ~~and 5.50% for the pre-65 and post-65 retirees during 2016, respectively, and the prescription cost is assumed to increase 11.00% during~~ ~~2016, after which these rates decrease until reaching the ultimate trend rate of~~ ~~5.00%~~ ~~in 2024.~~

~~CenterPoint Energy’s changes in accumulated comprehensive loss related to defined benefit, postretirement and other postemployment plans are as follows:~~

Year Ended December 31,
2015 2014
(in millions)
Beginning Balance $ (85 ) $ (88 )
Other comprehensive income (loss) before reclassifications (1) 21
(3 )
Amounts reclassified from accumulated other comprehensive income:
Prior service cost (2) 1
2
Actuarial losses (2) 10
9
Total reclassifications from accumulated other comprehensive income 11
11
Tax expense (12 ) (5 )
Net current period other comprehensive income 20
3
Ending Balance $ (65 ) $ (85 )



	December 31,
	2018			2017
	(in millions, except for actuarial assumptions)
Amounts Recognized in Balance Sheets
Current liabilities-other	$	(7	)	$	(7	)
Other liabilities-benefit obligations	(490		)	(417		)
Net liability, end of year	$	(497	)	$	(424	)
Actuarial Assumptions
Discount rate (2)	4.35		%	3.65		%
Expected return on plan assets (3)	6.00			6.00
Rate of increase in compensation levels	4.60			4.45
Interest crediting rate	3.75			3.75


(1)	~~Total other comprehensive income (loss) related~~Significant sources of gain for 2018 include the increase in discount rate from 3.65% to 4.35% and the ~~re-measurement~~mortality projection scale change from MP2017 to MP2018. For 2017, the significant source of ~~pension, postretirement and other postemployment plans.~~loss was the decrease in the discount rate from 4.15% to 3.65%.


(2)	~~These accumulated other comprehensive components are included in~~The discount rate assumption was determined by matching the ~~computation~~projected cash flows of ~~net periodic cost.~~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.

~~Amounts recognized in accumulated other comprehensive loss consist of the following:~~

December 31,
2015 2014

Pension
Benefits

Postretirement
Benefits

Pension
Benefits

Postretirement
Benefits
(in millions)
Unrecognized actuarial loss (gain) $ 106
$ (2 ) $ 113
$ 14
Unrecognized prior service cost (credit) 3
(1 ) 4
2
Net amount recognized in accumulated other comprehensive loss $ 109
$ (3 ) $ 117
$ 16

~~The changes in plan assets and benefit obligations recognized in other comprehensive income during~~ ~~2015~~ ~~are as follows:~~

Pension
Benefits

Postretirement
Benefits
(in millions)
Net gain $ —
$ 18
Amortization of net loss 7
1
Amortization of prior service credit 1
—
Total recognized in comprehensive income $ 8
$ 19

~~The total expense recognized in net periodic costs and other comprehensive income was~~ ~~$82 million~~ ~~and~~ ~~$-0-~~ ~~for pension and postretirement benefits, respectively, for the year ended~~ ~~December 31, 2015~~.

~~The amounts in accumulated other comprehensive loss expected to be recognized as components of net periodic benefit cost during~~ ~~2016~~ ~~are as follows:~~

Pension
Benefits

Postretirement
Benefits
(in millions)
Unrecognized actuarial loss $ 7
$ —
Unrecognized prior service cost 1
—
Amounts in accumulated comprehensive loss to be recognized in net periodic cost in 2016 $ 8
$ —


(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,								December 31,
	2015				2014				2018				2017
	Pension Qualified		Pension Non-qualified		Pension Qualified		Pension Non-qualified		Pension (Qualified)		Pension (Non-qualified)		Pension (Qualified)		Pension (Non-qualified)
	(in millions)								(in millions)
Accumulated benefit obligation	$	2,082	$	75	$	2,273	$	98	$	1,930	$	61	$	2,090	$	74
Projected benefit obligation	2,118		75		2,304		98		1,952		61		2,151		74
Fair value of plan assets	1,679		—		1,925		—		1,516		—		1,801		—

The accumulated benefit obligation for all defined benefit pension plans on CenterPoint Energy’s Consolidated Balance Sheets was $1,991 million and $2,164 million as of December 31, 2018 and 2017, respectively.

~~Assumed~~(c) Postretirement Benefits

CenterPoint Energy provides certain healthcare ~~cost trend rates~~and life insurance benefits for retired employees on both a contributory and non-contributory basis. The Registrants’ employees 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 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 ~~significant effect~~portion of their obligations in accordance with rate orders. All other obligations are funded on a pay-as-you-go basis.

Postretirement benefits are accrued over the ~~reported amounts for CenterPoint Energy’s~~active service period of employees. The net postretirement benefit ~~plans. A~~ cost includes the following components:



	Year Ended December 31,
	2018									2017									2016
	CenterPoint Energy			Houston Electric			CERC			CenterPoint Energy			Houston Electric			CERC			CenterPoint Energy			Houston Electric			CERC
	(in millions)
Service cost (1)	$	2		$	—		$	1		$	2		$	1		$	1		$	2		$	1		$	1
Interest cost (2)	13			8			4			16			9			5			16			10			4
Expected return on plan assets (2)	(5		)	(4		)	(1		)	(5		)	(4		)	(1		)	(6		)	(5		)	(1		)
Amortization of prior service cost (credit) (2)	(5		)	(5		)	1			(5		)	(6		)	1			(3		)	(4		)	—
Amortization of net loss (2)	—			—			—			—			—			—			1			1			1
Curtailment (3)	—			—			—			—			—			—			(5		)	(4		)	(1		)
Net postretirement benefit cost (credit)	$	5		$	(1	)	$	5		$	8		$	—		$	6		$	5		$	(1	)	$	4


(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. See Note 2(r).


(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. See Note 2(r).

(3)

A curtailment gain or loss is required when the expected future services of a significant number of current employees are reduced or eliminated for the accrual of benefits. During 2016, postretirement healthcare benefits were amended resulting in a net curtailment gain of $5 million. In May 2016, Houston Electric entered into a renegotiated collective bargaining agreement with the IBEW Local Union 66 that provides that for Houston Electric bargaining unit employees covered under the agreement who retire on or after January 1, 2017, retiree medical and prescription drug coverage will be provided exclusively through the NECA/IBEW Family Medical Care Plan in exchange for the payment of monthly premiums as determined under the agreement. As a result, the accrued postretirement benefits related to such future CenterPoint Energy and Houston Electric union retirees were eliminated. Houston Electric recognized a curtailment gain of $3 million as an accelerated recognition of the prior service credit that would otherwise be recognized in future periods for the postretirement plan. CenterPoint Energy also recognized an additional curtailment gain of $2 million in October 2016 related to other amendments in the postretirement plan.

The following assumptions were used to determine net periodic cost relating to postretirement benefits:



	Year Ended December 31,
	2018						2017						2016
	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC
Discount rate	3.60	%	3.60	%	3.60	%	4.15	%	4.15	%	4.15	%	4.35	%	4.35	%	4.35	%
Expected return on plan assets	4.55		4.75		3.85		4.50		4.75		3.60		4.80		5.00		3.95

1% ~~change~~The following table summarizes changes in the ~~assumed healthcare cost trend rate would have~~benefit obligation, plan assets, the ~~following effects:~~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, 2018 and 2017.

1%
Increase

1%
Decrease
(in millions)
Effect on the postretirement benefit obligation $ 12
$ 10
Effect on total of service and interest cost 1
1



	December 31,
	2018									2017
	CenterPoint Energy			Houston Electric			CERC			CenterPoint Energy			Houston Electric			CERC
	(in millions)
Change in Benefit Obligation
Benefit obligation, beginning of year	$	386		$	225		$	109		$	383		$	217		$	115
Service cost	2			—			1			2			1			1
Interest cost	13			8			4			16			9			5
Participant contributions	7			2			4			7			2			3
Benefits paid	(25		)	(13		)	(9		)	(26		)	(14		)	(9		)
Actuarial (gain) loss (1)	(52		)	(56		)	1			4			10			(6		)
Benefit obligation, end of year	331			166			110			386			225			109
Change in Plan Assets
Fair value of plan assets, beginning of year	120			93			26			113			88			25
Employer contributions	14			9			4			16			10			5
Participant contributions	7			2			4			7			2			3
Benefits paid	(25		)	(13		)	(9		)	(26		)	(14		)	(9		)
Actual investment return	(2		)	(2		)	—			10			7			2
Fair value of plan assets, end of year	114			89			25			120			93			26
Funded status, end of year	$	(217	)	$	(77	)	$	(85	)	$	(266	)	$	(132	)	$	(83	)
Amounts Recognized in Balance Sheets
Current liabilities-other	$	(6	)	$	—		$	(3	)	$	(6	)	$	—		$	(4	)
Other liabilities-benefit obligations	(211		)	(77		)	(82		)	(260		)	(132		)	(79		)
Net liability, end of year	$	(217	)	$	(77	)	$	(85	)	$	(266	)	$	(132	)	$	(83	)
Actuarial Assumptions
Discount rate (2)	4.35		%	4.35		%	4.35		%	3.60		%	3.60		%	3.60		%
Expected return on plan assets (3)	4.60			4.70			4.15			4.55			4.75			3.85
Medical cost trend rate assumed for the next year - Pre-65	5.95			5.95			5.95			6.15			6.15			6.15
Medical/prescription drug cost trend rate assumed for the next year - Post-65	28.60			28.60			28.60			23.85			23.85			23.85
Prescription drug cost trend rate assumed for the next year - Pre-65	9.20			9.20			9.20			9.85			9.85			9.85
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	2026			2026			2026			2026			2026			2026
Year that the cost trend rates reach the ultimate trend rate - Post-65	2027			2027			2027			2024			2024			2024


(1)	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 plans 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,
	2018								2017
	Pension Benefits		Postretirement Benefits						Pension Benefits		Postretirement Benefits
	CenterPoint Energy		CenterPoint Energy			CERC			CenterPoint Energy		CenterPoint Energy			CERC
	(in millions)
Unrecognized actuarial loss (gain)	$	109	$	(7	)	$	(3	)	$	94	$	(8	)	$	(2	)
Unrecognized prior service cost	1		5			5			1		6			6
Deferred tax benefit (1)	—		—			(9		)	—		—			(11		)
Net amount recognized in accumulated other comprehensive loss (gain)	$	110	$	(2	)	$	(7	)	$	95	$	(2	)	$	(7	)


(1)	CenterPoint Energy’s and CERC’s postretirement benefit obligation is reduced by the impact of previously non-taxable government subsidies under the Medicare Prescription Drug Act. Because the subsidies were non-taxable, the temporary difference used in measuring the deferred tax impact was determined on the unrecognized losses excluding such subsidies.

The changes in plan assets and benefit obligations recognized in other comprehensive income during 2018 are as follows:



	Pension Benefits			Postretirement Benefits
	CenterPoint Energy			CenterPoint Energy		CERC
	(in millions)
Net loss (gain)	$	22		$	—	$	(1	)
Amortization of net loss	(6		)	—		—
Amortization of prior service cost	(1		)	—		(1		)
Total recognized in comprehensive income	$	15		$	—	$	(2	)
Total expense recognized in net periodic costs and Other comprehensive income	$	76		$	5	$	3

(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 ~~benefit~~pension plans as of December 31, ~~2015:~~2018:



	~~Pension~~ ~~Benefits~~	~~Postretirement~~ ~~Benefits~~
U.S. equity	12 –- 28%	~~14 – 24%~~
International developed market equity	7 –- 17%	~~3 – 13%~~
Emerging market equity	~~3 – 13%~~	—	5 - 11%
Fixed income	~~54 – 66%~~	~~68 – 78%~~	55 - 65%
Cash	0 –- 2%	~~0 – 2%~~

The following tables set forth by level, within the fair value hierarchy (see Note 8)10), CenterPoint Energy’s pension plan assets at fair value as of December 31, ~~2015~~2018 and ~~2014~~2017:


											Fair Value Measurements as of December 31,
	Fair Value Measurements as of December 31, 2015										2018										2017
	Total			Quoted Prices in Active Markets for Identical Assets (Level 1)			Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		(Level 1)			(Level 2)		(Level 3)		Total			(Level 1)			(Level 2)		(Level 3)		Total
	(in millions)										(in millions)
Cash	$	11		$	11		$	—	$	—	$	19		$	—	$	—	$	19		$	18		$	—	$	—	$	18
Common collective trust funds (1)	896			—			896		—
Corporate bonds:
Investment grade or above	385			—			385		—		—			368		—		368			—			432		—		432
Equity securities:
International companies	38			38			—		—
U.S. companies	74			74			—		—		60			—		—		60			76			—		—		76
Cash received as collateral from securities lending	71			71			—		—		77			—		—		77			76			—		—		76
U.S. treasuries	57			57			—		—		196			—		—		196			67			—		—		67
Mortgage backed securities	4			—			4		—		—			6		—		6			—			8		—		8
Asset backed securities	3			—			3		—		—			1		—		1			—			1		—		1
Municipal bonds	66			—			66		—		—			27		—		27			—			47		—		47
Mutual funds (2)	144			144			—		—		167			—		—		167			211			—		—		211
International government bonds	1			—			1		—		—			16		—		16			—			17		—		17
Obligation to return cash received as collateral from securities lending	(71		)	(71		)	—		—		(77		)	—		—		(77		)	(76		)	—		—		(76		)
Total	$	1,679		$	324		$	1,355	$	—
Total investments at fair value											$	442		$	418	$	—	860			$	372		$	505	$	—	877
Investments measured by net asset value per share or its equivalent (1) (2)																		656										924
Total Investments																		$	1,516									$	1,801


(1)	~~60%~~ ~~of the amount invested~~Represents investments in common collective trust ~~funds was in fixed income securities,~~ ~~11%~~ ~~was in U.S. equities,~~ ~~23%~~ ~~was in international equities and~~ 2% ~~was in emerging market equities.~~ funds.


(2)	~~58%~~ ~~of the amount~~The amounts invested in mutual funds ~~was in international equities,~~ ~~28%~~ ~~was in emerging market equities~~ and~~14%~~ ~~was in U.S. equities.~~

Fair Value Measurements as of December 31, 2014
Total
Quoted Prices in
Active Markets for
Identical Assets
(Level 1)

Significant
Observable Inputs
(Level 2)

Significant
Unobservable
Inputs
(Level 3)
(in millions)
Cash $ 6
$ 6
$ —
$ —
Common collective trust funds (1) 1,108
—
1,108
—
Corporate bonds:

Investment grade or above 368
—
368
—
Equity securities:

International companies 49
49
—
—
U.S. companies 83
83
—
—
Cash received as collateral from securities lending 86
86
—
—
U.S. treasuries 47
47
—
—
Mortgage backed securities 4
—
4
—
Asset backed securities 4
—
4
—
Municipal bonds 79
—
79
—
Mutual funds (2) 161
161
—
—
International government bonds 15
—
15
—
Real estate 1
—
—
1
Obligation to return cash received as collateral from securities lending (86 ) (86 ) —
—
Total $ 1,925
$ 346
$ 1,578
$ 1


~~(1)~~	~~61%~~ ~~of the amount invested in~~ common collective trust funds ~~was in fixed income securities,~~ ~~14%~~ ~~was in U.S. equities,~~ ~~22%~~ ~~was in international equities and 3% was in emerging market equities.~~were allocated as follows:

~~(2)~~

~~57%~~ ~~of the amount invested in mutual funds was in international equities, 30% was in emerging market equities and~~ ~~13%~~ ~~was in U.S. equities.~~



	As of December 31,
	2018				2017
	Mutual Funds		Common Collective Trust Funds		Mutual Funds		Common Collective Trust Funds
International equities	51	%	37	%	57	%	34	%
Emerging market equities	34	%	4	%	30	%	5	%
U.S. equities	15	%	5	%	13	%	6	%
Fixed income	—		54	%	—		55	%

The pension plan 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 plan did not include any holdings of CenterPoint Energy ~~common stock~~Common Stock as of December 31, ~~2015~~2018 or ~~2014~~2017.

~~The changes~~(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 ~~the fair value~~making investment decisions and efficient and effective management of plan assets.

As part of the ~~pension plan’s level 3 investments~~investment strategy discussed above, the Registrants maintained the following weighted average allocation targets for the ~~years ended~~ postretirement plans as of December 31, ~~2015~~ ~~and~~ ~~2014~~ ~~were not material.~~2018:



	CenterPoint Energy	Houston Electric	CERC
U.S. equity	13 - 23%	13 - 23%	15 - 25%
International developed market equity	3 - 13%	3 - 13%	2 - 12%
Fixed income	69 - 79%	69 - 79%	68 - 78%
Cash	0 - 2%	0 - 2%	0 - 2%

The following ~~tables present~~table presents mutual funds by level, within the fair value hierarchy, ~~CenterPoint Energy’s~~the Registrants’ postretirement plan assets at fair value as of December 31, ~~2015~~2018 and ~~2014~~2017~~, by asset category:~~:

Fair Value Measurements as of December 31, 2015
Total
Quoted Prices
in Active
Markets for
Identical Assets
(Level 1)

Significant
Observable
Inputs
(Level 2)

Significant
Unobservable
Inputs
(Level 3)
(in millions)
Mutual funds (1) $ 136
$ 136
$ —
$ —
Total $ 136
$ 136
$ —
$ —



	Fair Value Measurements as of December 31,
	2018								2017
	Mutual Funds
	(Level 1)		(Level 2)		(Level 3)		Total		(Level 1)		(Level 2)		(Level 3)		Total
	(in millions)
CenterPoint Energy	$	114	$	—	$	—	$	114	$	120	$	—	$	—	$	120
Houston Electric	89		—		—		89		93		—		—		93
CERC	25		—		—		25		26		—		—		26


~~(1)~~	~~72%~~ ~~of the amount invested in mutual funds was in fixed income securities,~~ ~~20%~~ ~~was in U.S. equities and~~ 8% ~~was in international equities.~~ The amounts invested in mutual funds were allocated as follows:



	As of December 31,
	2018						2017
	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC
Fixed income	74	%	74	%	73	%	74	%	74	%	71	%
U.S. equities	19	%	19	%	21	%	18	%	18	%	21	%
International equities	7	%	7	%	6	%	8	%	8	%	8	%


~~(1)~~	~~73%~~ ~~of the amount invested in mutual funds was in fixed income securities,~~ ~~19%~~ ~~was in U.S. equities and~~ 8% ~~was in international equities.~~ (g) Benefit Plan Contributions

~~CenterPoint Energy contributed~~ ~~$35 million~~, ~~$31 million~~The Registrants made the following contributions in 2018 and ~~$18 million~~expect to ~~its qualified pension, non-qualified pension and postretirement benefits~~make the following minimum contributions in 2019 to the indicated benefit plans ~~respectively, in~~ ~~2015. CenterPoint Energy expects to contribute approximately~~ ~~$-0-~~, ~~$8 million~~ ~~and~~ ~~$16 million~~ ~~to its qualified pension, non-qualified pension and postretirement benefits plans, respectively, in~~ ~~2016~~.below:



	Contributions in 2018						Expected Minimum Contributions in 2019
	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC
	(in millions)
Qualified pension plan	$	60	$	—	$	—	$	86	$	—	$	—
Non-qualified pension plan	9		—		—		7		—		—
Postretirement benefit plan	14		9		4		17		10		4

The following benefit payments are expected to be paid by the pension and postretirement benefit plans:

Postretirement Benefit Plan

Pension
Benefits

Benefit
Payments

Medicare
Subsidy
Receipts
(in millions)
2016 $ 139
$ 32
$ (4 )
2017 144
34
(4 )
2018 155
35
(5 )
2019 157
37
(6 )
2020 163
38
(6 )
2021-2025 822
203
(41 )



	Pension Benefits		Postretirement Benefits
	CenterPoint Energy		CenterPoint Energy		Houston Electric		CERC
	(in millions)
2019	$	141	$	16	$	9	$	5
2020	146		19		10		6
2021	154		20		11		6
2022	155		21		11		7
2023	156		22		12		7
2024-2028	759		116		61		37

~~(c)~~(h) Savings Plan

The Registrants participate in CenterPoint ~~Energy has a~~Energy’s tax-qualified employee savings plan that includes a cash or deferred arrangement under Section 401(k) of the Internal Revenue Code of 1986, as amended (the Code), and an employee stock ownership plan ~~(ESOP)~~ under Section 4975(e)(7) of the Code. Under the plan, participating employees may ~~contribute a portion~~make pre-tax or Roth contributions up to 50%, and after tax contributions up to 16%, of their eligible compensation, ~~on a pre-tax or after-tax basis, generally up~~not to ~~a maximum of~~ ~~50%~~ ~~of eligible compensation.~~exceed certain federally mandated limits. The ~~Company matches~~Registrants match 100% of the first 6% of each employee’s compensation contributed. The matching contributions are fully vested at all times.

Participating employees may elect to invest all (prior to January 1, 2016) or a portion of their contributions to the plan in CenterPoint Energy common stock, to have dividends reinvested in additional shares or to receive dividend payments in cash on any investment in CenterPoint Energy common stock, and to transfer all or part of their investment in CenterPoint Energy common stock to other investment options offered by the plan.

Effective January 1, 2016, the savings plan was amended to limit the percentage of future contributions that could be invested in ~~CenterPoint Energy common stock~~Common Stock to 25% and to prohibit transfers of account balances where the transfer would result in more than 25% of a participant’s total account balance invested in ~~CenterPoint Energy common stock.~~Common Stock.

The savings plan has significant holdings of ~~CenterPoint Energy common stock.~~Common Stock. As of December 31, ~~2015~~2018, ~~16,942,974~~12,062,915 shares of ~~CenterPoint Energy’s common stock~~Common Stock were held by the savings plan, which represented approximately ~~17%~~16% of its investments. Given the concentration of the investments in ~~CenterPoint Energy’s common stock,~~Common Stock, the savings plan and its participants have market risk related to this investment.

CenterPoint ~~Energy’s~~Energy allocates to Houston Electric and CERC the savings plan benefit ~~expenses were~~ ~~$35 million~~, ~~$39 million~~expense related to their respective employees. The following table summarizes the Registrants’ savings plan benefit expense for 2018, 2017 and ~~$38 million~~ in ~~2015~~, ~~2014~~ ~~and~~ ~~2013, respectively.~~2016:

~~(d) Postemployment Benefits~~



	Year Ended December 31,
	2018						2017						2016
	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC
	(in millions)
Savings plan benefit expenses	$	43	$	17	$	18	$	41	$	17	$	17	$	38	$	15	$	16

(i) Other Benefits Plans

The Registrants participate in CenterPoint ~~Energy~~Energy’s plan that provides postemployment benefits for certain former or inactive employees, their beneficiaries and covered dependents, after employment but before retirement (primarily healthcare and life insurance benefits for participants in the long-term disability plan). ~~CenterPoint Energy recorded postemployment expenses of~~ ~~$2 million~~, ~~$3 million~~ ~~and~~ ~~$4 million~~ in ~~2015~~, ~~2014~~ ~~and~~ ~~2013, respectively.~~

~~Included~~The Registrants participate in ~~Benefit Obligations in the accompanying Consolidated Balance Sheets as of~~ ~~December 31, 2015~~ ~~and~~ ~~2014~~ ~~was~~ ~~$23 million~~ ~~and~~ ~~$28 million, respectively, relating to postemployment obligations.~~

~~(e) Other Non-Qualified Plans~~

CenterPoint ~~Energy has~~Energy’s non-qualified deferred compensation plans that provide benefits payable to directors, officers and ~~certain key~~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 ~~CenterPoint Energy. CenterPoint Energy~~the Registrants.

Expenses related to other benefit plans were recorded as follows:



	Year Ended December 31,
	2018						2017						2016
	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC
	(in millions)
Postemployment benefits	$	3	$	4	$	1	$	6	$	1	$	4	$	5	$	3	$	3
Deferred compensation plans	3		1		—		3		1		—		3		1		—

Amounts related to other benefit ~~expense relating to these~~ plans of ~~$3 million, $5 million and $5 million for the years in~~ ~~2015~~, ~~2014~~ ~~and~~ ~~2013, respectively. Included~~were included in Benefit Obligations in the Registrants’ accompanying Consolidated Balance Sheets as of ~~December 31, 2015~~ ~~and~~ ~~2014~~ ~~was~~ ~~$51 million~~ ~~and~~ ~~$60 million, respectively, relating to deferred compensation plans.~~follows:



	December 31, 2018						December 31, 2017
	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC
	(in millions)
Postemployment benefits	$	11	$	3	$	7	$	20	$	3	$	14
Deferred compensation plans	42		9		3		45		10		3
Split-dollar life insurance arrangements	36		1		—		39		1		—

~~Included in Benefit Obligations in CenterPoint Energy’s Consolidated Balance Sheets as of~~ ~~December 31, 2015~~ ~~and~~ ~~2014~~ ~~was~~ ~~$32 million~~ ~~and~~ ~~$33 million, respectively, relating to split-dollar life insurance arrangements.~~

~~(f)~~(j) Change in Control Agreements and Other Employee Matters

CenterPoint Energy ~~had change in control agreements with certain of its officers, which expired December 31, 2014. In lieu of these agreements, our Board of Directors approved~~has a ~~new~~ change in control plan, which was ~~effective January~~amended and restated on May 1, ~~2015.~~2017. The plan ~~like the expired agreements,~~ 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. ~~Our~~CenterPoint Energy officers, including ~~our~~the Executive Chairman, are participants under the plan.

As of December 31, ~~2015, approximately~~ ~~35%~~ ~~of CenterPoint Energy’s~~2018, the Registrants’ employees were ~~subject to collective bargaining agreements. The collective bargaining agreement with the International Brotherhood of Electrical Workers Local 66 and the two~~covered by collective bargaining agreements with Professional Employees International Union Local 12, which collectively cover approximately 21% of our employees, are scheduled to expire in March and May of 2016. We believe we have good relationships with these bargaining units and expect to negotiate new agreements in 2016.as follows:



		Percentage of Employees Covered
	Agreement Expiration	CenterPoint Energy		Houston Electric		CERC
IBEW Local 66	May 2020	18	%	51	%	—
OPEIU Local 12 and Mankato	March and May 2021	3	%	—		3	%
Gas Workers Union Local 340	April 2020	6	%	—		12	%
IBEW Local 949	December 2020	3	%	—		7	%
USW Locals 13-227 and 13-1	June and July 2022	5	%	—		11	%
Total		35	%	51	%	33	%

~~(7)~~ (9) Derivative Instruments

(a) Non-Trading Activities

Commodity Derivative Instruments.CenterPoint Energy ~~enters~~and CERC, through CES, enter into certain derivative instruments to ~~manage physical~~mitigate the effects of commodity price ~~risk and does not engage in proprietary or speculative commodity trading. These~~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. All other financial instruments do not qualify or are not designated as cash flow or fair value hedges.

Weather Hedges.CenterPoint Energy ~~has~~and CERC have weather normalization or other rate mechanisms that mitigate the impact of weather on NGD in Arkansas, Louisiana, Mississippi, Minnesota and Oklahoma. CenterPoint Energy’s and CERC’s NGD and CenterPoint Energy’s electric operations in Texas do not have such mechanisms, although fixed customer charges are historically higher in Texas for NGD compared to ~~CenterPoint Energy’s~~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 ~~Houston’s~~Energy’s electric operations’ results in its service territory.

CenterPoint Energy ~~has historically entered~~and CERC, as applicable, enter into ~~heating-degree day swaps~~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 ~~its~~ results of operations and cash ~~flows for the winter~~flows. These weather hedges are based on heating ~~season, which contained a bilateral dollar cap of $16 million in both 2013–2014 and 2014–2015. However, NGD did~~degree days at 10-year normal weather. Houston Electric does not enter into ~~heating-degree day swaps for the 2015–2016 winter season as a result of NGD’s Minnesota division implementing a full decoupling pilot in July 2015.~~weather hedges.

The table below summarizes CenterPoint ~~Energy also entered into~~Energy’s and CERC’s weather ~~hedges for the CenterPoint Houston service territory, which contained a bilateral~~hedge gain (loss) activity:



				Year Ended December 31,
Jurisdiction	Winter Season	Bilateral Cap		2018			2017			2016
		(in millions)
Certain NGD jurisdictions	2018 – 2019	$	9	$	—		$	—		$	—
Certain NGD jurisdictions	2017 – 2018	8		(2		)	—			—
Total CERC (1)				(2		)	—			—
Electric operations’ Texas service territory	2018 – 2019	8		—			—			—
Electric operations’ Texas service territory	2017 – 2018	9		(2		)	—			—
Electric operations’ Texas service territory	2016 – 2017	9		—			(1		)	1
Total CenterPoint Energy (1)				$	(4	)	$	(1	)	$	1

dollar cap of $8 million for both the 2013–2014 and 2014–2015 winter seasons and a bilateral dollar cap of $7 million for the 2015–2016 winter season. The swaps are based on 10-year normal weather. During the years ended December 31, 2015, 2014 and 2013, CenterPoint Energy recognized losses of $6 million, $11 million and $22 million, respectively, related to these swaps. Weather hedge gains and losses are included in revenues


(1)	Weather hedge gains (losses) are recorded in Revenues in the Statements of Consolidated Income.

Cash Flow Hedging of Interest Expense. From time to time, the Registrants enter into forward interest rate agreements with certain counterparties designated as cash flow hedges. The objective of these cash flow hedges is to reduce exposure to variability in cash flows related to interest payments on anticipated future fixed rate debt offerings or other exposure to variable rate debt. As of December 31, 2018 and 2017, the total outstanding notional amount of CenterPoint Energy’s and Houston Electric’s forward interest rate agreements related to cash flow hedges was $450 million and $-0-, respectively. The maximum length of time over which CenterPoint Energy and Houston Electric are exposed to the variability in future cash flows of the forecasted debt offerings is less than 12 months. For the impacts of cash flow hedges to accumulated other comprehensive income, see Note 13.

Economic Hedging of Interest Rate Risk. From time to time, the Registrants may enter into forward interest rate agreements with certain counterparties designated as economic hedges. The objective of these economic hedges is to offset any interest rate risk borne by one or more of the Registrants in connection with an anticipated future fixed rate debt offering or other exposure to variable rate debt. As of December 31, 2018 and 2017, the Registrants did not have any outstanding forward interest rate agreements related to economic hedges.

(b) Derivative Fair Values and Income Statement Impacts

The following tables present information about ~~CenterPoint Energy’s~~ derivative instruments and hedging activities. The first ~~four~~three tables provide a balance sheet overview of ~~CenterPoint Energy’s~~ Derivative Assets and Liabilities as of December 31, ~~2015~~2018 and ~~2014~~,2017, while the last ~~table provides~~three tables provide a breakdown of the related income statement impacts for the years ending December 31, ~~2015~~2018, 2017 and ~~2014~~.

2016.


Fair Value of Derivative Instruments	Fair Value of Derivative Instruments						Fair Value of Derivative Instruments
		December 31, 2015
Total derivatives not designated as hedging instruments		Balance Sheet Location	Derivative Assets Fair Value		Derivative Liabilities Fair Value
			(in millions)						December 31, 2018				December 31, 2017
								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:							Derivatives designated as cash flow hedges:
Interest rate derivatives								Current Liabilities: Non-trading derivative liabilities	$	—	$	24	$	—	$	—
								Total Houston Electric	—		24		—		—
Derivatives designated as fair value hedges:							Derivatives designated as fair value hedges:
Natural gas derivatives (1) (2) (3)								Current Liabilities: Non-trading derivative liabilities	1		7		13		1
Derivatives not designated as hedging instruments:							Derivatives not designated as hedging instruments:
Natural gas derivatives (1) (2) (3)		Current Assets: Non-trading derivative assets	$	90	$	2		Current Assets: Non-trading derivative assets	103		3		114		4
Natural gas derivatives (1) (2) (3)		Other Assets: Non-trading derivative assets	36		—			Other Assets: Non-trading derivative assets	38		—		44		—
Natural gas derivatives (1) (2) (3)		Current Liabilities: Non-trading derivative liabilities	10		60			Current Liabilities: Non-trading derivative liabilities	62		173		38		78
Natural gas derivatives (1) (2) (3)		Other Liabilities: Non-trading derivative liabilities	4		25			Other Liabilities: Non-trading derivative liabilities	16		25		9		24
								Total CERC	220		208		218		107
Indexed debt securities derivative		Current Liabilities	—		442			Current Liabilities	—		601		—		668
Total			$	140	$	529
								Total CenterPoint Energy	$	220	$	833	$	218	$	775

(1)

The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling ~~767~~ ~~billion cubic feet (Bcf)~~1,674 Bcf or a net ~~112~~140 Bcf long ~~position. Of the~~position and 1,795 Bcf or a net 224 Bcf long position as of December 31, 2018 and 2017, respectively. Certain natural gas contracts hedge basis ~~swaps constitute~~ ~~133~~ ~~Bcf.~~

risk only and lack a fixed price exposure.

(2)

Natural gas contracts are presented on a net basis in the Consolidated Balance ~~Sheets. Natural gas contracts~~Sheets as they are subject to master netting arrangements. This netting applies to all undisputed amounts due or past due and causes derivative assets (liabilities) to be ultimately presented net in a liability (asset) account within the Consolidated Balance Sheets. The net of total non-trading natural gas derivative assets and liabilities ~~was a $109 million asset as shown on CenterPoint Energy’s Consolidated Balance Sheets (and as~~is detailed in the Offsetting of Natural Gas Derivative Assets and Liabilities table ~~below), and was comprised of the natural gas contracts derivative assets and liabilities separately shown above offset by collateral netting of $56 million.~~below.


(3)	Derivative Assets and Derivative Liabilities include no material amounts related to physical forward transactions with Enable.

Offsetting of Natural Gas Derivative Assets and Liabilities
December 31, 2015

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 $ 100
$ (11 ) $ 89
Other Assets: Non-trading derivative assets 40
(4 ) 36
Current Liabilities: Non-trading derivative liabilities (62 ) 51
(11 )
Other Liabilities: Non-trading derivative liabilities (25 ) 20
(5 )
Total $ 53
$ 56
$ 109



Cumulative Basis Adjustment for Fair Value Hedges (CenterPoint Energy and CERC)
		December 31, 2018				December 31, 2017
	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	$	57	$	1	$	80	$	14
Total CenterPoint Energy and CERC		$	57	$	1	$	80	$	14


~~(1)~~	~~Gross amounts recognized include some derivative assets and liabilities that are not subject to master netting arrangements.~~


~~(2)~~	The derivative assets and liabilities on the Consolidated Balance Sheets exclude accounts receivable or accounts payable that, should they exist, could be used as offsets to these balances in the event of a default.

Fair Value of Derivative Instruments
December 31, 2014
Total derivatives not designated
as hedging instruments

Balance Sheet
Location

Derivative
Assets
Fair Value

Derivative
Liabilities
Fair Value
(in millions)
Natural gas derivatives (1) (2) (3) Current Assets: Non-trading derivative assets $ 101
$ 1
Natural gas derivatives (1) (2) (3) Other Assets: Non-trading derivative assets 32
—
Natural gas derivatives (1) (2) (3) Current Liabilities: Non-trading derivative liabilities 14
83
Natural gas derivatives (1) (2) (3) Other Liabilities: Non-trading derivative liabilities 2
18
Indexed debt securities derivative Current Liabilities —
541
Total $ 149
$ 643


~~(1)~~	~~The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling~~ ~~804~~ ~~Bcf or a net~~ 60 ~~Bcf long position. Of the net long position, basis swaps constitute~~ ~~127~~ ~~Bcf.~~

~~(2)~~

Natural gas contracts are presented on a net basis in the Consolidated Balance Sheets. Natural gas contracts are subject to master netting arrangements. This netting applies to all undisputed amounts due or past due and causes derivative assets (liabilities) to be ultimately presented net in a liability (asset) account within the Consolidated Balance Sheets. The net of total non-trading derivative assets and liabilities was a ~~$111 million~~ asset as shown on CenterPoint Energy’s Consolidated Balance Sheets (and as detailed in the table below), and was comprised of the natural gas contracts derivative assets and liabilities separately shown above, offset by collateral netting of ~~$64 million~~.


~~(3)~~	~~Derivative Assets and Derivative Liabilities include no material amounts related to physical forward transactions with Enable.~~


Offsetting of Natural Gas Derivative Assets and Liabilities
Offsetting of Natural Gas Derivative Assets and Liabilities (CenterPoint Energy and CERC)										Offsetting of Natural Gas Derivative Assets and Liabilities (CenterPoint Energy and CERC)
	December 31, 2014										December 31, 2018									December 31, 2017
	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)			Gross Amounts Recognized (1)			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amount Presented in the Consolidated Balance Sheets (2)
	(in millions)										(in millions)
Current Assets: Non-trading derivative assets	$	115		$	(16	)	$	99			$	166		$	(66	)	$	100		$	165		$	(55	)	$	110
Other Assets: Non-trading derivative assets	34			(2		)	32				54			(16		)	38			53			(9		)	44
Current Liabilities: Non-trading derivative liabilities	(84		)	65			(19		)		(183		)	81			(102		)	(83		)	63			(20		)
Other Liabilities: Non-trading derivative liabilities	(18		)	17			(1		)		(25		)	20			(5		)	(24		)	20			(4		)
Total	$	47		$	64		$	111			$	12		$	19		$	31		$	111		$	19		$	130


(1)	Gross amounts recognized include some derivative assets and liabilities that are not subject to master netting arrangements.


(2)	The derivative assets and liabilities on the Consolidated Balance Sheets exclude accounts receivable or accounts payable that, should they exist, could be used as offsets to these balances in the event of a default.

~~For CenterPoint Energy’s price stabilization activities~~Income Statement Impact of ~~the Natural Gas Distribution business segment, the settled costs of derivatives are ultimately recovered through purchased gas adjustments. Accordingly, the net unrealized gains~~Hedge Accounting Activity (CenterPoint Energy and losses associated with these contracts are recorded as net regulatory assets. Realized and unrealized gains and losses on other derivatives are recognized in the Statements of Consolidated Income as revenue for retail sales derivative contracts and as natural gas expense for financial natural gas derivatives and non-retail related physical natural gas derivatives. Unrealized gains and losses on indexed debt securities are recorded as Other Income (Expense) in the Statements of Consolidated Income.CERC)

~~100~~

Income Statement Impact of Derivative Activity
Year Ended December 31,
Total derivatives not designated
as hedging instruments
Income Statement Location 2015 2014 2013
(in millions)
Natural gas derivatives Gains in Revenue $ 134
$ 35
$ 11
Natural gas derivatives (1) Gains (Losses) in Expense: Natural Gas (105 ) 11
10
Indexed debt securities derivative Gains (Losses) in Other Income (Expense) 74
(86 ) (193 )
Total $ 103
$ (40 ) $ (172 )



	Year Ended December 31,
	2018			2017			2016
	Location and Amount of Gain (Loss) recognized in Income on Hedging Relationship (2)
	Non-utility natural gas expense
	(in millions)
Total amounts presented in the statements of income in which the effects of hedges are recorded	$	4,364		$	3,785		$	1,983

Gain (loss) on fair value hedging relationships:
Commodity contracts:
Hedged items - Natural gas inventory	(13		)	14			—
Derivatives designated as hedging instruments	13			(14		)	—
Amounts excluded from effectiveness testing recognized in earnings immediately (1)	(149		)	(67		)	70

(1)

~~The Gains (Losses)~~Upon adoption of ASU 2017-12 effective January 1, 2018 (see Note 2 for additional information), CenterPoint Energy and CERC elected to exclude from their assessment of hedge effectiveness the natural gas market price difference between locations of the hedged inventory and the delivery location specified in ~~Expense: Natural Gas includes $-0-~~the hedge instruments. Prior to the adoption of this accounting guidance, the timing difference between the spot price and ~~$2 million during~~the futures price, as well as the difference between the timing of the settlement of the futures and the valuation of the underlying physical commodity, was excluded from the assessment of effectiveness for CenterPoint Energy’s and CERC’s existing fair value hedges and will continue to be excluded from the assessment of hedge effectiveness. CenterPoint Energy and CERC elected to continue to immediately recognize amounts excluded from hedge effectiveness in their respective Statements of Consolidated Income.


(2)	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 Registrants for the years ended December 31, ~~2015~~2018, 2017 and ~~2014, respectively, related to physical forwards purchased from Enable.~~2016, respectively.



		Year Ended December 31,
	Income Statement Location	2018			2017		2016
		(in millions)
Effects of derivatives not designated as hedging instruments on the income statement:
Commodity contracts	Gains (Losses) in Non-utility revenues	$	107		$	211	$	(18	)
Total CERC		107			211		(18		)
Indexed debt securities derivative	Gains (Losses) in Other Income (Expense)	(232		)	49		(413		)
Interest rate derivatives	Gains in Other Income (Expense)	2			—		—
Total CenterPoint Energy		$	(123	)	$	260	$	(431	)

CenterPoint Energy ~~enters~~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 ~~Standard & Poor’s Ratings Services~~S&P or Moody’s ~~Investors Service, Inc.~~ credit ratings of CenterPoint Energy, Inc. or its subsidiaries, including CERC Corp., are downgraded. ~~The total fair value of the derivative instruments that contain credit risk contingent features that are in a net liability position at~~ ~~December 31, 2015~~ ~~and~~ ~~2014~~ ~~was~~ ~~$3 million~~ ~~and $2 million, respectively.~~

CenterPoint Energy posted no assets as collateral towards derivative instruments that contain credit risk contingent features at either December 31, 2015 or 2014. If all derivative contracts (in a net liability position) containing credit risk contingent features were triggered at both ~~December 31, 2015~~and ~~2014~~, ~~$2 million~~ ~~of additional assets would be required to be posted as collateral.~~CERC



	December 31, 2018		December 31, 2017
	(in millions)
Aggregate fair value of derivatives containing material adverse change provisions in a net liability position	$	1	$	2
Fair value of collateral already posted	—		—
Additional collateral required to be posted if credit risk contingent features triggered	—		2

(d) Credit Quality of Counterparties

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 table shows the composition of counterparties to the non-trading derivative ~~assets of CenterPoint Energy as of~~ ~~December 31, 2015~~ ~~and~~ ~~2014~~:

assets:


CenterPoint Energy and CERC
	December 31, 2015				December 31, 2014				December 31, 2018				December 31, 2017
	Investment Grade(1)		Total		Investment Grade(1)		Total		Investment Grade (1)		Total (3)		Investment Grade (1)		Total (3)
	(in millions)								(in millions)
Energy marketers	$	4	$	10	$	2	$	4	$	11	$	24	$	6	$	45
End users (2)	2		115		2		127		30		114		17		109
Total	$	6	$	125	$	4	$	131	$	41	$	138	$	23	$	154

(1)

“Investment grade” is primarily determined using publicly available credit ratings and considers credit support (including parent company guarantees) and collateral (including cash and standby letters of credit). For unrated counterparties, CenterPoint Energy ~~determines~~and CERC determine a synthetic credit rating by performing financial statement analysis and ~~considers~~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.

~~(8)~~ (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.~~securities, as well as natural gas inventory that has been designated as the hedged item in a fair value hedge.

~~101~~

Level 2: Inputs, other than quoted prices included in Level 1, are observable for the asset or liability, either directly or indirectly. Level 2 inputs include quoted prices for similar instruments in active markets, and inputs other than quoted prices that are observable for the asset or liability. Fair value assets and liabilities that are generally included in this category are derivatives with fair values based on inputs from actively quoted markets. A market approach is utilized to value the Registrants’ Level 2 natural gas derivative assets or liabilities. CenterPoint Energy’s Level 2 ~~assets or liabilities.~~indexed debt securities derivative is valued using an option model and a discounted cash flow model, which uses projected dividends on the ZENS-Related Securities and a discount rate as observable inputs.

Level 3: Inputs are unobservable for the asset or liability, and include situations where there is little, if any, market activity for the asset or liability. Unobservable inputs reflect ~~CenterPoint Energy’s~~the Registrants’ judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. ~~CenterPoint Energy develops~~The Registrants develop these inputs based on the best information available, including ~~CenterPoint Energy’s~~the Registrants’ own data. A market approach is utilized to value ~~CenterPoint Energy’s~~the Registrants’ Level 3 assets or liabilities. AtAs of December 31, ~~2015,~~2018, 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 ~~$1.36~~$1.39 to ~~$3.29~~$5.96 per one million British thermal units (Btu)) as an unobservable input. Level 3 options are valued through Black-Scholes (including forward start) option models which include option volatilities (ranging from 0 to ~~82%~~)MMBtu) 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) ~~and their fair value is sensitive to forward prices and volatilities. If forward prices decrease, CenterPoint Energy’s~~. Forward price decreases (increases) as of December 31, 2018 would have resulted in lower (higher) values, respectively, for long forwards ~~lose value whereas its~~and options and higher (lower) values, respectively, for short forwards ~~gain in value. If volatility decreases, CenterPoint Energy’s long options lose value whereas its short options gain in value.~~and options.

~~CenterPoint Energy determines~~The Registrants determine the appropriate level for each financial asset and liability on a quarterly basis and ~~recognizes~~recognize transfers between levels at the end of the reporting period. ~~For the year ended~~ ~~December 31, 2015, there were no transfers between Level 1 and 2. CenterPoint Energy also recognizes purchases of Level 3 financial assets and liabilities at their fair market value at the end of the reporting period.~~

The following tables present information about ~~CenterPoint Energy’s~~the Registrants’ assets and liabilities (including derivatives that are presented net) measured at fair value on a recurring basis as of December 31, ~~2015~~2018 and ~~2014~~,December 31, 2017, and indicate the fair value hierarchy of the valuation techniques utilized by ~~CenterPoint Energy~~the Registrants to determine such fair value.

CenterPoint Energy


	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Netting Adjustments ⁽¹⁾			Balance as of December 31, 2015		December 31, 2018											December 31, 2017
	(in millions)											Level 1 (4)		Level 2		Level 3		Netting (1)			Total		Level 1 (4)		Level 2		Level 3		Netting (1)			Total
Assets												(in millions)
Corporate equities	$	807	$	—	$	—	$	—		$	807	$	542	$	—	$	—	$	—		$	542	$	963	$	—	$	—	$	—		$	963
Investments, including money market funds(2)	53		—		—		—			53		66		—		—		—			66		68		—		—		—			68
Natural gas derivatives (2)	4		115		21		(15		)	125
Natural gas derivatives (3)(4)												—		173		47		(82		)	138		—		161		57		(64		)	154
Hedged portion of natural gas inventory												1		—		—		—			1		14		—		—		—			14
Total assets	$	864	$	115	$	21	$	(15	)	$	985	$	609	$	173	$	47	$	(82	)	$	747	$	1,045	$	161	$	57	$	(64	)	$	1,199
Liabilities
Indexed debt securities derivative	$	—	$	442	$	—	$	—		$	442	$	—	$	601	$	—	$	—		$	601	$	—	$	—	$	668	$	—		$	668
Natural gas derivatives (2)	13		65		9		(71		)	16
Interest rate derivatives												24		—		—		—			24		—		—		—		—			—
Natural gas derivatives (3)(4)												—		191		17		(101		)	107		—		96		11		(83		)	24
Total liabilities	$	13	$	507	$	9	$	(71	)	$	458	$	24	$	792	$	17	$	(101	)	$	732	$	—	$	96	$	679	$	(83	)	$	692


~~(1)~~	~~Amounts represent the impact of legally enforceable master netting arrangements that allow CenterPoint Energy to settle positive and negative positions and also include cash collateral of~~ ~~$56 million~~ ~~posted with the same counterparties.~~


~~(2)~~	~~Natural gas derivatives include no material amounts related to physical forward transactions with Enable.~~

~~102~~Houston Electric

Quoted Prices in
Active Markets
for Identical Assets
(Level 1)

Significant Other
Observable
Inputs
(Level 2)

Significant
Unobservable
Inputs
(Level 3)

Netting
Adjustments ⁽¹⁾
Balance as of December 31, 2014
(in millions)
Assets
Corporate equities $ 932
$ —
$ —
$ —
$ 932
Investments, including money market funds 54
—
—
—
54
Natural gas derivatives (2) 7
122
20
(18 ) 131
Total assets $ 993
$ 122
$ 20
$ (18 ) $ 1,117
Liabilities

Indexed debt securities derivative $ —
$ 541
$ —
$ —
$ 541
Natural gas derivatives 22
77
3
(82 ) 20
Total liabilities $ 22
$ 618
$ 3
$ (82 ) $ 561



	December 31, 2018										December 31, 2017
	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)	$	48	$	—	$	—	$	—	$	48	$	51	$	—	$	—	$	—	$	51
Total assets	$	48	$	—	$	—	$	—	$	48	$	51	$	—	$	—	$	—	$	51
Liabilities
Interest rate derivatives	$	24	$	—	$	—	$	—	$	24	$	—	$	—	$	—	$	—	$	—
Total liabilities	$	24	$	—	$	—	$	—	$	24	$	—	$	—	$	—	$	—	$	—

CERC



	December 31, 2018											December 31, 2017
	Level 1 (4)		Level 2		Level 3		Netting (1)			Total		Level 1 (4)		Level 2		Level 3		Netting (1)			Total
Assets	(in millions)
Corporate equities	$	2	$	—	$	—	$	—		$	2	$	3	$	—	$	—	$	—		$	3
Investments, including money market funds (2)	11		—		—		—			11		11		—		—		—			11
Natural gas derivatives (3)(4)	—		173		47		(82		)	138		—		161		57		(64		)	154
Hedged portion of natural gas inventory	1		—		—		—			1		14		—		—		—			14
Total assets	$	14	$	173	$	47	$	(82	)	$	152	$	28	$	161	$	57	$	(64	)	$	182
Liabilities
Natural gas derivatives (3)(4)	$	—	$	191	$	17	$	(101	)	$	107	$	—	$	96	$	11	$	(83	)	$	24
Total liabilities	$	—	$	191	$	17	$	(101	)	$	107	$	—	$	96	$	11	$	(83	)	$	24


(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 of ~~$64~~$19 million as of both December 31, 2018 and 2017, respectively, posted with the same counterparties.


(2)	Amounts are included in Prepaid and Other Current Assets and Other Assets in the Consolidated Balance Sheets.


(3)	Natural gas derivatives include no material amounts related to physical forward transactions with Enable.

(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 ~~tables present~~table presents additional information about assets or liabilities, including derivatives that are measured at fair value on a recurring basis for which CenterPoint Energy ~~has~~and CERC have utilized Level 3 inputs to determine fair value:

Fair Value Measurements Using Significant
Unobservable Inputs (Level 3)
Derivative assets and liabilities, net
Year Ended December 31,
2015 2014 2013
(in millions)
Beginning balance $ 17
$ 3
$ 2
Total gains 7
14
3
Total settlements (12 ) 1
(3 )
Transfers out of Level 3 (1 ) —
—
Transfers into Level 3 1
(1 ) 1
Ending balance (1) $ 12
$ 17
$ 3
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
$ 6
$ 16
$ 2



	Year Ended December 31,
	2018						2017						2016
	CenterPoint Energy			CERC			CenterPoint Energy			CERC			CenterPoint Energy			CERC
	(in millions)
Beginning balance	$	(622	)	$	46		$	(704	)	$	13		$	12		$	12
Purchases (1)	—			—			—			—			12			12
Total gains (losses)	30			30			96			47			12			12
Total settlements	(39		)	(39		)	(11		)	(11		)	(27		)	(27		)
Transfers into Level 3 (2)	5			5			14			14			(712		)	5
Transfers out of Level 3 (3)	656			(12		)	(17		)	(17		)	(1		)	(1		)
Ending balance (4)	$	30		$	30		$	(622	)	$	46		$	(704	)	$	13

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:
	$	18		$	18		$	87		$	38		$	(402	)	$	11


(1)	Mark-to-market value of Level 3 derivative assets acquired through the purchase of AEM were less than $1 million at the acquisition date.


(2)	During ~~2015, 2014 and 2013,~~2016, CenterPoint Energy transferred its indexed debt securities from Level 2 to Level 3 to reflect changes in the significance of the unobservable inputs used in the valuation.


(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)	CenterPoint Energy and CERC did not have significant Level 3 ~~purchases~~sales during any of the years ended December 31, 2018, 2017 or ~~sales.~~2016.

Items Measured at Fair Value on a Nonrecurring Basis

Based on the sustained low Enable common unit price and further declines in such price during the three months ended September 30, 2015 and December 31, 2015, respectively, as well as the market outlook for continued depressed crude oil and natural gas prices impacting the midstream oil and gas industry, CenterPoint Energy determined in connection with its preparation of financial statements for the three months ended September 30, 2015 and December 31, 2015, respectively, that an other than temporary decrease in the value of its investment in Enable had occurred. The impairment analyses compared the estimated fair value of CenterPoint Energy’s investment in Enable to its carrying value. The fair value of the investment was determined using multiple valuation methodologies under both the market and income approaches.

~~103~~

~~Both of these approaches incorporate significant estimates and assumptions, including:~~

~~Market Approach~~

~~volume weighted average quoted price of Enable’s common units;~~

~~recent market transactions of comparable companies; and~~

~~EBITDA to total enterprise multiples for comparable companies.~~

~~Income Approach~~

~~Enable’s forecasted cash distributions;~~

~~projected cash flows of incentive distribution rights;~~

~~forecasted growth rate of Enable’s cash distributions; and~~

~~determination of the cost of equity, including market risk premiums.~~

~~Weighting of the different approaches~~

Significant unobservable inputs used include the growth rate applied to the projected cash distributions beyond 2020 and the discount rate used to determine the present value of the estimated future cash flows. CenterPoint Energy based its assumptions on projected financial information that CenterPoint Energy believes is reasonable; however, actual results may differ materially from those projections. Based on the significant unobservable estimates and assumptions required, CenterPoint Energy concluded that the fair value estimate should be classified as a Level 3 measurement within the fair value hierarchy.

As a result of the analysis, CenterPoint Energy recorded other than temporary impairments on its investment in Enable of $250 million and $975 million during the three months ended September 30, 2015 and December 31, 2015, respectively. See Note 9 for further discussion of the impairments. As of December 31, ~~2014,~~2018 and 2017, there were no significant assets or liabilities measured at fair value on a nonrecurring basis.

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 ~~2.0% Zero-Premium Exchangeable Subordinated Notes due 2029 (ZENS)~~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 ~~the market price.~~a combination of historical trading prices and comparable issue data. These ~~assets and~~ 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 ~~1 or Level~~ 2 in the fair value hierarchy.

December 31, 2015 December 31, 2014

Carrying
Amount

Fair
Value

Carrying
Amount

Fair
Value
(in millions)
Financial assets:
Notes receivable - affiliated companies $ 363
$ 356
$ 363
$ 362
Financial liabilities:
Long-term debt $ 8,620
$ 9,101
$ 8,652
$ 9,427



	December 31, 2018						December 31, 2017
	CenterPoint Energy (1)		Houston Electric (1)		CERC		CenterPoint Energy (1)		Houston Electric (1)		CERC
Long-term debt, including current maturities	(in millions)
Carrying amount	$	9,140	$	4,717	$	2,371	$	8,679	$	4,753	$	2,457
Fair value	9,308		4,770		2,488		9,220		5,034		2,708


(1)	Includes Securitization Bond debt.

~~(9)~~ ~~Unconsolidated Affiliates~~

~~On May 1, 2013 (the Closing Date) CERC Corp., OGE~~(11) Unconsolidated Affiliate (CenterPoint Energy ~~Corp. (OGE)~~ and ~~ArcLight Capital Partners, LLC (ArcLight) closed on~~CERC)

CenterPoint Energy has the ~~formation~~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. Upon the adoption of ASU 2014-09 and ASU 2017-05 on January 1, 2018, CenterPoint Energy ~~recorded an equity method~~and CERC evaluated transactions in the investment in Enable atthat occurred prior to January 1, 2018 (the effective date) and concluded a cumulative effect adjustment to the ~~historical cost~~opening balance of ~~the contributed net assets.~~retained earnings was not required. See Note 22(r) for further ~~information on the formation of Enable.~~discussion.

~~104~~

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, 2018, CenterPoint Energy’s maximum exposure to loss related to Enable ~~a VIE in which CenterPoint Energy is not the primary beneficiary,~~ is limited to ~~its~~the equity investment, ~~as presented~~its investment in the Consolidated Balance Sheet as of December 31, 2015, CERC Corp.’s guarantee of collection of Enable’s $1.1 billion senior notes due 2019 and 2024 (Guaranteed Senior Notes) and other guarantees discussed in Note 14,Enable Series A Preferred Units and outstanding current accounts receivable from Enable. ~~As of December 31, 2015, certain of the entities contributed to Enable~~

On September 4, 2018, CERC entered into a Contribution Agreement, by and between CERC and CNP Midstream, a new subsidiary formed by CERC ~~Corp. were obligated on approximately $363 million~~in June 2018, pursuant to which CERC contributed its equity investment in Enable consisting of ~~notes owed~~Enable common units and its interests in Enable GP, to CNP Midstream (collectively, the Enable Contribution). Immediately following the Enable Contribution, CERC distributed all of its interest in CNP Midstream to Utility Holding, CERC’s sole stockholder and a wholly-owned subsidiary of CenterPoint Energy. Utility Holding then distributed all of its interest in CNP Midstream to CenterPoint Energy, its sole member (collectively with the Enable Contribution, the Internal Spin). CERC ~~Corp., which bore interest~~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 has been accounted for under the guidance for transactions between entities under common control. As of September 4, 2018, CERC derecognized its investment in Enable at ~~an annual rate~~carrying value on the date of ~~2.10% to 2.45%. Enable redeemed such notes scheduled to mature~~distribution of $2.4 billion, net of deferred income taxes of $974 million, and CNP Midstream recorded the net asset contribution from CERC at CERC’s carrying value. Neither CERC nor CNP Midstream recognized a gain or loss upon the distribution or contribution, respectively, of net assets involved in ~~2017 in~~the Internal Spin. In connection with the ~~private placement discussed further in Note 18.~~Internal Spin, CenterPoint Energy, ~~recorded interest income of $8~~through Utility Holding, made a $600 million ~~during both the year ended December 31, 2015 and 2014, and had interest receivable from Enable of $4 million as of both December 31, 2015 and 2014, on its notes receivable from Enable.~~

Effective on the Closing Date, CenterPoint Energy and Enable entered into a Services Agreement, Employee Transition Agreement, Transitional Seconding Agreement and other agreements (Transition Agreements). Under the Services Agreement, CenterPoint Energy agreedcapital contribution to ~~provide certain support services~~CERC, which was used by CERC to Enable such as accounting, legal, risk management and treasury functions for an initial term ending on April 30, 2016, after which such services continue on a year-to-year basis unless terminated by Enable with at least 90 days’ notice. CenterPoint Energy expects to provide certain services to Enable following the completion of the initial term.

CenterPoint Energy provided seconded employees to Enable to support its operations for a term ending on December 31, 2014. Enable, at its discretion, had the right to select and offer employment to seconded employees from CenterPoint Energy. During the fourth quarter of 2014, Enable notified CenterPoint Energyrepay outstanding indebtedness that it selected seconded employees and provided employment offers to substantially all of the seconded employees from CenterPoint Energy. Substantially all of the seconded employees became employees of Enable effective January 1, 2015.historically supported CERC’s legacy midstream assets. See Note 621 for ~~additional information.~~

On April 16, 2014, Enable completed its initial public offering (IPO) of 28,750,000 common units, at a price of $20.00 per unit, which included 3,750,000 common units sold by ArcLight pursuant to an over-allotment option that was fully exercised by the underwriters. Enable received $464 million in net proceeds from the sale of the units, after deducting underwriting fees, structuring fees and other offering costs. In connection with Enable’s IPO, a portion of CenterPoint Energy’s common units were converted into subordinated units, as discussed further ~~below. Subsequent to the IPO, Enable continues to be controlled jointly by CenterPoint Energy and OGE.~~discussion.

As a result of ~~Enable’s IPO, CenterPoint Energy’s limited partner interest~~the Internal Spin, CERC’s equity in Enable was reduced from approximately 58.3% to approximately 54.7%. CenterPoint Energy accounted for the dilution of its investment in Enable as a result of Enable’s IPO as a failed partial sale of in-substance real estate. CenterPoint Energy did not receive any cash from Enable’s IPO and, as such, CenterPoint Energy did not recognize a gain or loss. CenterPoint Energy’s basis difference in Enable was reduced for the impact of the Enable IPO.

In accordance with the Enable formation agreements, CenterPoint Energy had certain put rights, and Enable had certain call rights, exercisable with respect to the 25.05% interest in Southeast Supply Header, LLC (SESH) retained by CenterPoint Energy on the Closing Date, under which CenterPoint Energy would contribute its retained interest in SESH, in exchange for a specified number of limited partner common unitsearnings in Enable and ~~a cash payment, payable either from CenterPoint Energy to Enable or from Enable to CenterPoint Energy, to the extent of changes~~related income taxes have been classified as discontinued operations in the value of SESH subject to certain restrictions. Specifically, the rights were exercisable with respect to (1) a 24.95% interest in SESH, which closed on May 30, 2014 and (2) a 0.1% interest in SESH, which closed on June 30, 2015.CERC’s Consolidated Financial Statements as detailed below.

~~CenterPoint Energy billed Enable for reimbursement of transition services, including the costs of seconded employees, $16 million~~Limited Partner Interest and $163 million during the years ended December 31, 2015 and 2014, respectively, under the Transition Agreements. Actual transition services costs are recorded net of reimbursements received from Enable. CenterPoint Energy had accounts receivable from Enable of $3 million and $28 million as of December 31, 2015 and 2014, respectively, for amounts billed for transition services, including the cost of seconded employees.

CenterPoint Energy incurred natural gas expenses, including transportation and storage costs, of $117 million and $130 million during the year ended December 31, 2015 and 2014, respectively, for transactions with Enable. CenterPoint Energy had accounts payable to Enable of $11 million and $23 million at December 31, 2015 and 2014, respectively, from such transactions.

~~As of December 31, 2015, CenterPoint Energy held an approximate 55.4% limited partner interest~~Units Held in Enable ~~consisting of 94,151,707 common units and 139,704,916 subordinated units. As of December 31, 2015, CenterPoint~~(CenterPoint Energy and ~~OGE each own a 50% management interest in the general partner of Enable and a 40% and 60% interest, respectively, in the incentive distribution rights held by the general partner.~~

~~105~~

CenterPoint Energy recognized a loss of $1,633 million from its investment in Enable as of December 31, 2015. This loss included impairment charges totaling $1,846 million composed of CenterPoint Energy’s impairment of its investment in Enable of $1,225 million and CenterPoint Energy’s share, $621 million, of impairment charges Enable recorded for goodwill and long-lived assets.

CenterPoint Energy evaluates its equity method investments for impairment when factors indicate that a decrease in the value of its investment has occurred and the carrying amount of its investment may not be recoverable. An impairment loss, based on the excess of the carrying value over estimated fair value of the investment, is recognized in earnings when an impairment is deemed to be other than temporary. Considerable judgment is used in determining if an impairment loss is other than temporary and the amount of any impairment. Based on the sustained low Enable common unit price and further declines in such price during the three months ended September 30, 2015 and December 31, 2015, respectively, as well as the market outlook for continued depressed crude oil and natural gas prices impacting the midstream oil and gas industry, CenterPoint Energy determined in connection with its preparation of financial statements for the three months ended September 30, 2015 and December 31, 2015, that an other than temporary decrease in the value of its investment in Enable had occurred. CenterPoint Energy wrote down the value of its investment in Enable to its estimated fair value which resulted in impairment charges of $250 million as of September 30, 2015 and $975 million as of December 31, 2015. Both the income approach and market approach were utilized to estimate the fair value of CenterPoint Energy’s total investment in Enable, which includes the limited partner common and subordinated units, general partner interest and incentive distribution rights held by CenterPoint Energy. The determination of fair value considered a number of relevant factors including Enable’s common unit price and forecasted results, recent comparable transactions and the limited float of Enable’s publicly traded common units. See Note 8 for further discussion of the determination of fair value of CenterPoint Energy’s investment in Enable.

~~Investment in Unconsolidated Affiliates:~~CERC):

Year Ended December 31,
2015 2014
(in millions)
Enable $ 2,594
$ 4,520
SESH (1) —
1
Total $ 2,594
$ 4,521



	As of December 31,
	2018				2017
	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)	54.0	%	233,856,623	14,520,000	54.1	%	233,856,623	14,520,000
OGE	25.6	%	110,982,805	—	25.7	%	110,982,805	—
Public unitholders	20.4	%	88,392,983	—	20.2	%	87,744,652	—


(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, 2018 and 2017. No impairment charges or adjustment to carrying value were made as no observable price changes were identified in the current or prior reporting periods. See Note 2(r) for further discussion.


(3)	Prior to the Internal Spin on September 4, 2018 described above, CenterPoint Energy’s investment in Enable’s common units, excluding the Enable Series A Preferred Units held directly by CenterPoint Energy, ~~disposed of its remaining interest in SESH on June 30, 2015.~~was held indirectly through CERC.

~~Equity~~

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 ~~Earnings (Losses)~~Enable or sales to any person or entity (including a series of ~~Unconsolidated Affiliates, net:~~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 and CERC):

CenterPoint Energy and OGE held the following interests in Enable GP as of both December 31, 2018 and 2017:

Year Ended December 31,
2015 2014 2013
(in millions)
Enable $ (1,633 ) $ 303
$ 173
SESH (1) —
5
15
Total $ (1,633 ) $ 308
$ 188



	Management Rights (1)		Incentive Distribution Rights (2)
CenterPoint Energy (3)	50	%	40	%
OGE	50	%	60	%


(1)	As of December 31, 2018, Enable is controlled jointly by CenterPoint Energy ~~contributed~~and OGE. Sale of CenterPoint Energy’s or OGE’s ownership interests in Enable GP to a ~~24.95%~~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 ~~SESH~~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 ~~on May 30, 2014~~GP and its ~~remaining interest~~affiliates, within 60 days after the end of each quarter. If cash distributions to Enable’s unitholders exceed $0.330625 per common unit in ~~SESH~~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 ~~June 30, 2015.~~Enable’s cash distributions at the time of the exercise of this reset election. To date, no incentive distributions have been made.


(3)	CenterPoint Energy held the management rights and incentive distributions rights in Enable GP indirectly through CERC until the Internal Spin on September 4, 2018 described above.

Distributions Received from Enable (CenterPoint Energy and CERC):

~~106~~



	Year Ended December 31,
	2018				2017				2016
	Per Unit		Cash Distribution		Per Unit		Cash Distribution		Per Unit		Cash Distribution
	(in millions, except per unit amounts)
Enable common units (1)	$	0.9540	$	223	$	1.2720	$	297	$	1.2720	$	297
Total CERC			223				297				297
Enable common units (1)	0.3180		74		—		—		—		—
Enable Series A Preferred Units (2)	2.5000		36		2.5000		36		1.5417		22
Total CenterPoint Energy			$	333			$	333			$	319


(1)	Reflects CERC’s ownership of Enable common units up to September 4, 2018 when CERC completed the Internal Spin. After such date, distributions from Enable were received directly by CenterPoint Energy.


(2)	2016 amounts represent the period from February 18, 2016 to December 31, 2016.

Transactions with Enable (CenterPoint Energy and CERC):



	Year Ended December 31,
	2018		2017		2016
CenterPoint Energy and CERC	(in millions)
Natural gas expenses, including transportation and storage costs	$	122	$	115	$	110
CenterPoint Energy
Reimbursement of transition services (1)	4		4		7


(1)	Represents amounts billed under the Transition Agreements for certain support services provided to Enable. Actual transition services costs are recorded net of reimbursement.



	December 31,
	2018		2017
CenterPoint Energy and CERC	(in millions)
Accounts payable for natural gas purchases from Enable	$	11	$	13
CenterPoint Energy
Accounts receivable for amounts billed for transition services	2		1

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,							Year Ended December 31,
	2015			2014		2013		2018			2017		2016
	(in millions)							(in millions)
Operating revenues	$	2,418		$	3,367	$	2,123	$	3,431		$	2,803	$	2,272
Cost of sales, excluding depreciation and amortization	1,097			1,914		1,241		1,819			1,381		1,017
Impairment of goodwill and other long-lived assets	1,134			8		12
Operating income (loss)	(712		)	586		322
Net income (loss) attributable to Enable	(752		)	530		289
Depreciation and amortization								398			366		338
Operating income								648			528		385
Net income attributable to Enable common units								485			400		290

Reconciliation of Equity in Earnings (Losses), net:
CenterPoint Energy’s interest	$	(416	)	$	298	$	168	$	262		$	216	$	160
Basis difference amortization (1)	8			5		5		47			49		48
Impairment of CenterPoint Energy’s equity method investment in Enable	(1,225		)	—		—
CenterPoint Energy’s equity in earnings (losses), net (2)	$	(1,633	)	$	303	$	173
Loss on dilution, net of proportional basis difference recognition								(2		)	—		—
CenterPoint Energy’s equity in earnings, net								$	307		$	265	$	208

(1)

Equity in earnings of unconsolidated ~~affiliates~~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 over approximately 3330 years, the remaining average life of the assets to which the basis difference is attributed.


~~(2)~~	These amounts include CenterPoint Energy’s share of Enable’s impairment of goodwill and long-lived assets and the impairment of CenterPoint Energy’s equity method investment in Enable totaling $1,846 million during the year ended December 31, 2015. This impairment is offset by $213 million of earnings for the year ended December 31, 2015.

Summarized consolidated balance sheet information for Enable is as follows:


	December 31,						December 31,
	2015			2014			2018			2017
	(in millions)						(in millions)
Current assets	$	381		$	438		$	449		$	416
Non-current assets	10,857			11,399			11,995			11,177
Current liabilities	615			671			1,615			1,279
Non-current liabilities	3,092			2,343			3,211			2,660
Non-controlling interest	12			31			38			12
Enable partners’ capital	7,519			8,792

Preferred equity							362			362
Enable partners’ equity							7,218			7,280
Reconciliation of Investment in Enable:
CenterPoint Energy’s ownership interest in Enable partners’ capital	$	4,163		$	4,869
CenterPoint Energy’s ownership interest in Enable partners’ equity							$	3,896		$	3,935
CenterPoint Energy’s basis difference	(1,569		)	(349		)	(1,414		)	(1,463		)
CenterPoint Energy’s investment in Enable	$	2,594		$	4,520
CenterPoint Energy’s equity method investment in Enable							$	2,482		$	2,472

~~107~~

~~Distributions Received~~

Discontinued Operations (CERC):

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 ~~Unconsolidated Affiliates:~~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,
2015 2014 2013
(in millions)
Enable $ 294
$ 298
$ 106
SESH (1) —
7
23
Total $ 294
$ 305
$ 129



	Year Ended December 31,
	2018		2017		2016
	(in millions)
Equity in earnings of unconsolidated affiliate, net	$	184	$	265	$	208
Income tax expense	46		104		81
Income from discontinued operations, net of tax	$	138	$	161	$	127


~~(1)~~	~~CenterPoint Energy contributed a 24.95% interest in SESH to Enable on each of May 1, 2013 and May 30, 2014 and its remaining interest in SESH to Enable on June 30, 2015.~~

~~(10)~~ (12) Indexed Debt Securities (ZENS) and Securities Related to ZENS(CenterPoint Energy)

(a) Investment in Securities Related to ZENS

In 1995, CenterPoint Energy sold a cable television subsidiary to ~~Time Warner, Inc. (TW)~~TW and received ~~TW securities~~certain ZENS-Related Securities as partial consideration. A subsidiary of CenterPoint Energy ~~now~~ holds~~7.1 million~~ shares of ~~TW common stock (TW Common),~~ ~~1.8 million~~ ~~shares of Time Warner Cable Inc. (TWC) common stock (TWC Common) and 0.9 million shares of Time Inc. common stock (Time Common) (together with~~certain securities detailed in the ~~TW Common and TWC Common, the TW Securities)~~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 TWZENS-Related Securities are recorded in CenterPoint Energy’s Statements of Consolidated Income.



	Shares Held at December 31,
	2018	2017
AT&T Common	10,212,945	—
Charter Common	872,912	872,503
Time Common	—	888,392
TW Common	—	7,107,130

(b) ZENS

In September 1999, CenterPoint Energy issued ZENS having an original principal amount of $1 billion of which $828 million ~~remain~~remained outstanding atas of December 31, ~~2015~~2018. Each ZENS ~~note~~ was originally exchangeable at the holder’s option at any time for an amount of cash equal to 95% of the market value of the reference shares of TW Common attributable to such note. The number and identity of the reference shares attributable to each ZENS ~~note~~ are adjusted for certain corporate events. ~~Prior~~

On October 22, 2016, AT&T announced that it had entered into a definitive agreement to acquire TW in a stock and cash transaction. On February 15, 2017, TW shareholders approved the ~~closing~~announced transaction with AT&T. The merger closed on June 14, 2018. CenterPoint Energy received $53.75 and 1.437 shares of ~~the merger discussed below, the reference shares~~AT&T Common for each ~~ZENS note consisted of 0.5~~ share of TW Common ~~0.125505 share~~held, resulting in cash proceeds of ~~TWC Common, 0.045455 share of AOL Inc. common stock (AOL Common)~~$382 million and ~~0.0625 share of Time Common.~~

~~On May 26, 2015, Verizon Communications, Inc. (Verizon) initiated a tender offer to purchase all outstanding~~10,212,945 shares of AOL Common for $50 per share, in which CenterPoint Energy tendered all of its shares of AOL Common for $32 million. Verizon acquired the remaining eligible shares through a merger, which closed on June 23, 2015.AT&T Common. In accordance with the terms of the ZENS, CenterPoint Energy remitted ~~$32~~$382 million to ZENS note holders in July ~~2015,~~2018, which reduced the ZENS contingent principal. As a result, CenterPoint Energy recorded a reduction in the indexed debt securities derivative liability of $18 million, a reduction in the indexed debt balance of $7 million and a loss of $7 million, which is included in Gain (loss) on indexed debt securities on the Statements of Consolidated Income. As of December 31, 2015, the reference shares for each ZENS note consisted of 0.5 share of TW Common, 0.125505 share of TWC Common and 0.0625 share of Time Common.principal amount.

On ~~May~~November 26, ~~2015, Charter Communications, Inc. (Charter)~~2017, Meredith announced that it had entered into a definitive merger agreement with ~~TWC. On September 21, 2015, Charter shareholders approved the announced transaction with TWC.~~Time. Pursuant to the merger agreement, upon closing of the merger, ~~TWC~~a subsidiary of Meredith would purchase for cash all outstanding Time Common shares ~~would be exchanged~~ for $18.50 per share. The transaction was consummated on January 31, 2018. CenterPoint Energy elected to make a reference share offer adjustment and distribute additional interest, if any, in accordance with the terms of its ZENS rather than electing to increase the early exchange ratio to 100%. CenterPoint Energy’s distribution of additional interest in connection with the reference share offer was proportionate to the percentage of eligible shares that were validly tendered by Time stockholders in Meredith’s tender offer. CenterPoint Energy received $18.50 for each share of Time Common held, resulting in cash ~~and Charter stock and as~~proceeds of approximately

$16 million. In accordance with the terms of the ZENS, CenterPoint Energy distributed additional interest of approximately $16 million to ZENS holders on March 6, 2018, which reduced the ZENS contingent principal amount.

As a result, CenterPoint Energy recorded the following during the year ended December 31, 2018 related to the events discussed above:



	Meredith/Time			AT&T/TW
	(in millions)
Cash payment to ZENS note holders	$	16		$	382
Indexed debt – reduction	(4		)	(95		)
Indexed debt securities derivative – reduction	(1		)	(45		)
Loss on indexed debt securities	$	11		$	242

CenterPoint Energy’s reference shares ~~would consist~~for each ZENS consisted of ~~Charter stock, TW Common and Time Common. The merger is expected to close by June of 2016.~~the following:



	December 31,
	2018	2017
	(in shares)
AT&T Common	0.7185	—
Charter Common	0.061382	0.061382
Time Common	—	0.0625
TW Common	—	0.5

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 ZENS is subject to being increased or decreased to the extent that the annual yield from interest and cash dividends on the reference shares is less than or more than 2.309%. The adjusted principal amount is defined in the ZENS instrument as “contingent principal.” At December 31, ~~2015~~2018, ZENS having an original principal amount of $828 million and a contingent principal amount of ~~$705~~$93 million were outstanding and were exchangeable, at the option of the holders, for cash equal to 95% of the market value of reference shares deemed to be attributable to the ZENS. As of December 31, ~~2015~~2018, the market value of such shares was approximately ~~$805~~$540 million, which would provide an exchange amount of ~~$923~~$620 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-~~

~~108~~

~~current~~then-current market value of the reference shares, which will include any additional publicly-traded securities distributed with respect to the current reference shares prior to maturity.

The ZENS obligation is bifurcated into a debt component and a derivative component (the holder’s option to receive the appreciated value of the reference shares at maturity). The bifurcated debt component accretes through interest charges ~~at 17.4%~~ annually up to the contingent principal amount of the ZENS in 2029. Such accretion will be reduced by annual cash interest payments, as described above. The derivative component is recorded at fair value and changes in the fair value of the derivative component are recorded in CenterPoint Energy’s Statements of Consolidated Income. Changes in the fair value of the TWZENS-Related Securities held by CenterPoint Energy are expected to substantially offset changes in the fair value of the derivative component of the ZENS.

The following table sets forth summarized financial information regarding CenterPoint Energy’s investment in TWZENS-Related Securities and each component of CenterPoint Energy’s ZENS obligation.


	TW Securities			Debt Component of ZENS			Derivative Component of ZENS			ZENS-Related Securities			Debt Component of ZENS			Derivative Component of ZENS
	(in millions)									(in millions)
Balance as of December 31, 2012	$	540		$	138		$	268
Balance as of December 31, 2015										$	805		$	145		$	442
Accretion of debt component of ZENS	—			24			—			—			26			—
2% interest paid	—			(17		)	—			—			(17		)	—
Sale of TW Securities	(9		)	—			—
Redemption of indexed debt securities	—			(2		)	(6		)
Sale of ZENS-Related Securities										(178		)	—			—
Distribution to ZENS holders										—			(40		)	(21		)
Loss on indexed debt securities	—			—			193			—			—			296
Gain on TW Securities	236			—			—
Balance as of December 31, 2013	767			143			455
Gain on ZENS-Related Securities										326			—			—
Balance as of December 31, 2016										953			114			717
Accretion of debt component of ZENS	—			26			—			—			27			—
2% interest paid	—			(17		)	—			—			(17		)	—
Loss on indexed debt securities	—			—			86
Gain on TW Securities	163			—			—
Balance as of December 31, 2014	930			152			541
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	—			26			—			—			21			—
2% interest paid	—			(17		)	—			—			(17		)	—
Sale of TW securities	(32		)	—			—
Sale of ZENS-Related Securities										(398		)	—			—
Distribution to ZENS holders	—			(7		)	(18		)	—			(102		)	(46		)
Gain on indexed debt securities	—			—			(81		)	—			—			(21		)
Loss on TW Securities	(93		)	—			—
Balance as of December 31, 2015	$	805		$	154		$	442
Loss on ZENS-Related Securities										(22		)	—			—
Balance as of December 31, 2018										$	540		$	24		$	601

~~(11)~~ (13) Equity~~Equity~~(CenterPoint Energy)

~~Capital Stock~~

~~CenterPoint Energy has~~ ~~1,020,000,000~~ ~~authorized shares of capital stock, comprised of~~ ~~1,000,000,000~~ ~~shares of~~ ~~$0.01~~ ~~par value common stock and~~ ~~20,000,000~~ ~~shares of~~ ~~$0.01~~ ~~par value cumulative preferred stock.~~

Dividends Declared

CenterPoint Energy declared dividends on its Common Stock during 2018, 2017 and 2016 as presented in the table below:



Declaration Date	Record Date	Payment Date	Per Share		Total (in millions)
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

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



Declaration Date	Record Date	Payment Date	Per Share		Total (in millions)
October 27, 2016	November 16, 2016	December 9, 2016	$	0.2575	$	111
July 28, 2016	August 16, 2016	September 9, 2016	0.2575		111
April 28, 2016	May 16, 2016	June 10, 2016	0.2575		111
January 20, 2016	February 16, 2016	March 10, 2016	0.2575		110
Total 2016			$	1.0300	$	443

CenterPoint Energy declared dividends on its Series A Preferred Stock during 2018 as presented in the table below:



Declaration Date	Record Date	Payment Date	Per Share		Total
					(in millions)
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 2018 as presented in the table below:



Declaration Date	Record Date	Payment Date	Per Share		Total
					(in millions)
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 and 2016.

Dividend Requirement on Preferred Stock



	Year Ended December 31,
	2018		2017		2016
	(in millions)
Series A Preferred Stock	$	18	$	—	$	—
Series B Preferred Stock	17		—		—
Total preferred stock dividend requirement	$	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. ~~$0.99~~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.

~~$0.95~~Fundamental Change Conversion. ~~and~~ ~~$0.83, respectively,~~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 ~~years ended~~ ~~December 31, 2015~~, ~~2014~~period beginning on, and ~~2013~~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.

~~109~~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;

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, ~~2015~~2018 and ~~2014,~~2017, CenterPoint Energy’s consolidated retained earnings balance includes undistributed earnings from Enable of ~~$-0-~~$31 million and ~~$71 million,~~$-0-, respectively.

Accumulated Other Comprehensive Income (Loss)

Changes in accumulated comprehensive income (loss) are as follows:



	Year Ended December 31,
	2018									2017
	CenterPoint Energy			Houston Electric			CERC			CenterPoint Energy			Houston Electric			CERC
	(in millions)
Beginning Balance	$	(68	)	$	—		$	6		$	(71	)	$	1		$	3
Other comprehensive income (loss) before reclassifications:
Remeasurement of pension and other postretirement plans	(19		)	—			1			4			—			7
Deferred loss from interest rate derivatives (1)	(19		)	(18		)	(1		)	(5		)	(1		)	(2		)
Amounts reclassified from accumulated other comprehensive loss:
Prior service cost (2)	1			—			1			1			—			1
Actuarial losses (2)	6			—			—			7			—			—
Tax benefit (expense)	6			4			(1		)	(4		)	—			(3		)
Net current period other comprehensive income (loss)	(25		)	(14		)	—			3			(1		)	3
Adoption of ASU 2018-02	(15		)	—			(1		)	—			—			—
Ending Balance	$	(108	)	$	(14	)	$	5		$	(68	)	$	—		$	6


(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 less than $1 million for each of the years ended December 31, 2018 and 2017, 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.

~~(12)~~ (14) Short-term Borrowings and Long-term Debt

December 31,
2015 December 31,
2014
Long-Term Current (1) Long-Term Current (1)
(in millions)
Short-term borrowings:
Inventory financing $ —
$ 40
$ —
$ 53
Total short-term borrowings —
40
—
53
Long-term debt:

CenterPoint Energy:

ZENS (2) —
154
—
152
Senior notes 5.95% to 6.85% due 2017 to 2018 550
—
550
200
Pollution control bonds 5.05% to 5.125% due 2018 to 2028 (3) 118
—
118
69
Commercial paper (4) 716
—
191
—
Other —
3
2
2
CenterPoint Houston:

Bank Loans 200
—
—
—
First mortgage bonds 9.15% due 2021 102
—
102
—
General mortgage bonds 2.25% to 6.95% due 2022 to 2044 1,912
—
1,912
—
System restoration bonds 3.46% to 4.243% due 2018 to 2022 365
50
415
48
Transition bonds 0.901% to 5.302% due 2017 to 2024 1,918
341
2,259
324
Other —
—
1
—
CERC Corp.:

Senior notes 4.50% to 6.625% due 2016 to 2041 1,843
325
2,168
—
Commercial paper (4) 219
—
341
—
Unamortized discount and premium, net (42 ) —
(50 ) —
Total long-term debt 7,901
873
8,009
795
Total debt $ 7,901
$ 913
$ 8,009
$ 848



	December 31, 2018					December 31, 2017
	Long-Term			Current (1)		Long-Term			Current (1)
	(in millions)
CERC (2):
Short-term borrowings:
Inventory financing (3)	$	—		$	—	$	—		$	39
Total short-term borrowings	—			—		—			39
Long-term debt:
Senior notes 3.55% to 6.625% due 2021 to 2047	2,193			—		1,593			—
Commercial paper (4)	210			—		898			—
Unamortized debt issuance costs	(15		)	—		(12		)	—
Unamortized discount and premium, net	(17		)	—		(22		)	—
Total CERC long-term debt	2,371			—		2,457			—
Total CERC debt	2,371			—		2,457			39
Houston Electric:
First mortgage bonds 9.15% due 2021	102			—		102			—
General mortgage bonds 1.85% to 6.95% due 2021 to 2048	3,212			—		2,812			—
Restoration Bond Company:
System restoration bonds 4.243% due 2022	197			59		256			56
Bond Company II:
Transition bonds 5.302% due 2019	—			208		208			194
Bond Company III:
Transition bonds 5.234% due 2020	29			56		85			53
Bond Company IV:
Transition bonds 2.161% to 3.028% due 2020 to 2024	753			135		888			131
Unamortized debt issuance costs	(24		)	—		(22		)	—
Unamortized discount and premium, net	(11		)	—		(10		)	—
Total Houston Electric debt	4,258			458		4,319			434
CenterPoint Energy:
ZENS due 2029 (5)	—			24		—			122
Senior notes 2.50% to 4.25% due 2021 to 2028	2,000			—		500			—
Pollution control bonds 5.125% due 2028 (6)	68			—		68			50
Commercial paper (4)	—			—		855			—
Unamortized debt issuance costs	(13		)	—		(4		)	—
Unamortized discount and premium, net	(2		)	—		—			—
Total CenterPoint Energy long-term debt	8,682			482		8,195			606
Total CenterPoint Energy debt	$	8,682		$	482	$	8,195		$	645


(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 10(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.Issued by CERC Corp.


(3)	~~$118 million~~ ~~of these series of debt were secured by general mortgage bonds of~~ CenterPoint ~~Houston as of both December 31, 2015~~Energy’s and ~~2014~~. CERC’s NGD has AMAs associated with its utility distribution service in Arkansas, Louisiana, Mississippi, Oklahoma and Texas. In March 2018, NGD’s third-party AMAs in Arkansas, Louisiana and Oklahoma

expired, and NGD entered into new AMAs with CES effective April 1, 2018 in these states. The AMAs have varying terms, the longest of which expires in 2021. Pursuant to the provisions of the agreements, NGD sells natural gas and agrees to repurchase an equivalent amount of natural gas during the winter heating seasons at the same cost.


(4)	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.


(5)	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.

~~(a) Short-term Borrowings~~


(6)	$68 million and $118 million of these series of debt were secured by general mortgage bonds of Houston Electric as of December 31, 2018 and 2017, respectively.

~~Inventory Financing~~. NGD has asset management agreements associated with its utility distribution service in Arkansas, north Louisiana and Oklahoma that extend through 2019. Pursuant to the provisions of the agreements, NGD sells natural gas and agrees

~~110~~

to repurchase an equivalent amount of natural gas during the winter heating seasons at the same cost, plus a financing charge. These transactions are accounted for as a financing and they had an associated principal obligation of ~~$40 million~~ ~~and~~ ~~$53 million~~ ~~as of~~ ~~December 31, 2015~~ ~~and~~ ~~2014, respectively.~~

~~(b)~~ Long-term Debt

Debt ~~Repayments.~~Retirements. In June 2015, CenterPoint Energy repaid its $200 million 6.85% Senior Notes using proceeds from its commercial paper program. In October 2015, CenterPoint Energy repaid its $69 million 4.9% pollution control bonds using proceeds from its commercial paper program. CenterPoint Energy’s $1.2 billion revolving credit facility backstops its $1.0 billion commercial paper program.

~~Retirement of Bonds.~~ ~~In November 2015,~~During the year ended December 31, 2018, CenterPoint Energy retired ~~$740 million of tax-exempt municipal bonds that had been held for remarketing.~~the following debt instrument at maturity:

Registrant

Retirement Date

Debt Instrument

Aggregate Principal Amount (1)

Interest Rate

Maturity Date

(in millions)

CenterPoint Energy

November 2018

Pollution control bonds

5.050%

2018


(1)	Secured by general mortgage bonds of Houston Electric.

~~Transition~~Debt Issuances. During the year ended December 31, 2018 and ~~System Restoration~~in January 2019, the Registrants issued the following debt instruments:



Registrant	Issuance Date	Debt Instrument	Aggregate Principal Amount		Interest Rate	Maturity Date
			(in millions)
Houston Electric (1)	February 2018	General mortgage bonds	$	400	3.95%	2048
CERC (1) (2)	March 2018	Unsecured senior notes	300		3.55%	2023
CERC (1) (2)	March 2018	Unsecured senior notes	300		4.00%	2028
CenterPoint Energy (3)	October 2018	Unsecured senior notes	500		3.60%	2021
CenterPoint Energy (3)	October 2018	Unsecured senior notes	500		3.85%	2024
CenterPoint Energy (3)	October 2018	Unsecured senior notes	500		4.25%	2028
Houston Electric (1)	January 2019	General mortgage bonds	700		4.25%	2049


(1)	Proceeds from these debt issuances were used for general limited liability company and corporate purposes, as applicable, including capital expenditures, repayment of portions of outstanding commercial paper and borrowings under CenterPoint Energy’s money pool.


(2)	Issued by CERC Corp.


(3)	Proceeds from these debt issuances were used to fund a portion of the Merger and to pay related fees and expenses.

Securitization Bonds. As of December 31, ~~2015~~,2018, CenterPoint Energy and Houston Electric had special purpose subsidiaries consisting of ~~transition and system restoration bond companies,~~the Bond Companies, which ~~it consolidates.~~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 ~~transition bonds and system restoration bonds~~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 ~~payable by most of CenterPoint Houston’s retail electric customers in order~~ to provide recovery of authorized qualified costs. CenterPoint Energy and Houston ~~has~~Electric have no payment obligations in respect of the ~~transition and system restoration bonds~~Securitization Bonds other than to remit the applicable transition or system restoration charges ~~it collects.~~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 ~~CenterPoint~~ Houston Electric have no recourse to any assets or revenues of the ~~transition and system restoration bond companies~~Bond Companies (including the transition and system restoration charges), and the holders of ~~transition bonds or system restoration bonds~~Securitization Bonds have no recourse to the assets or revenues of CenterPoint Energy or ~~CenterPoint Houston.~~Houston Electric.

Credit Facilities.In April 2018, CenterPoint Energy obtained commitments by lenders to provide a $5 billion Bridge Facility to provide flexibility for the timing of the long-term acquisition financing and fund, in part, amounts payable by CenterPoint Energy in connection with the Merger. In May 2018, CenterPoint Energy entered into an amendment to its revolving credit facility to increase the aggregate commitments from $1.7 billion to $3.3 billion effective the earlier of (i) the termination of all commitments by certain lenders to provide the Bridge Facility and (ii) the payment in full of all obligations (other than contingent obligations) under the Bridge Facility and termination of all commitments to advance additional credit thereunder, and in each case, so long as the Merger Agreement has not been terminated pursuant to the terms thereof without consummation of the Merger. This increase to CenterPoint Energy’s revolving credit facility will automatically expire on the termination date of the revolving credit facility. In addition, the amendment provided for a temporary increase on the maximum ratio of debt for borrowed money to capital from 65% to 75% until the earlier of (i) June 30, 2019 and (ii) the termination of all commitments in respect of the Bridge Facility without any borrowing thereunder. On October 5, 2018, CenterPoint Energy terminated all remaining commitments by lenders to provide the Bridge Facility. As a result, the aggregate commitments under the revolving credit facility automatically increased from $1.7 billion to $3.3 billion and the maximum ratio of debt for borrowed money to capital reverted to 65%.

As of December 31, ~~2015~~2018 and ~~2014, CenterPoint Energy, CenterPoint Houston and CERC Corp.~~2017, the Registrants had the following revolving credit facilities and utilization of such facilities:


			December 31, 2015								December 31, 2014							December 31, 2018										December 31, 2017
	Size of Facility		Loans			Letters of Credit		Commercial Paper			Loans		Letters of Credit		Commercial Paper			Size of Facility		Loans		Letters of Credit		Commercial Paper		Weighted Average Interest Rate		Size of Facility		Loans		Letters of Credit		Commercial Paper		Weighted Average Interest Rate
	(in millions)																	(in millions, except weighted average interest rate)
CenterPoint Energy	$	1,200	$	—		$	6	$	716	(1)	$	—	$	6	$	191	(1)	$	3,300	$	—	$	6	$	—	—		$	1,700	$	—	$	6	$	855	1.88	%
CenterPoint Houston	300		200		(2)	4		—			—		4		—
CERC Corp.	600		—			2		219		(3)	—		—		341		(3)
Houston Electric																		300		—		4		—		—		300		—		4		—		—
CERC (1)																		900		—		1		210		2.93	%	900		—		1		898		1.72	%
Total	$	2,100	$	200		$	12	$	935		$	—	$	10	$	532		$	4,500	$	—	$	11	$	210			$	2,900	$	—	$	11	$	1,753


(1)	~~Weighted average interest rate was 0.79%~~Issued by CERC Corp.

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 ~~0.63%~~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 ~~December 31, 2015 and 2014, respectively.~~the closing of the Merger.


(2)	~~Weighted average interest rate was 1.637%~~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.



Execution Date	Registrant	Size of Facility			Draw Rate of LIBOR plus (1)	Financial Covenant Limit on Debt for Borrowed Money to Capital Ratio (2)	Debt for Borrowed Money to Capital Ratio as of December 31, 2018 (3)	Termination Date (4)
		(in millions)
March 3, 2016	CenterPoint Energy	$	3,300	(5)	1.250%	65%	44.9%	March 3, 2022
March 3, 2016	Houston Electric	300			1.125%	65%	49.2%	March 3, 2022
March 3, 2016	CERC (6)	900			1.125%	65%	46.8%	March 3, 2022


(1)	Based on credit ratings as of December 31, ~~2015.~~2018.

(2)

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.


(3)	~~Weighted average interest rate was 0.81% and 0.68%~~As defined in the revolving credit facility agreement, excluding Securitization Bonds.


(4)	Amended on June 16, 2017 to extend the termination date.


(5)	Pursuant to the amendment entered into in May 2018, the aggregate commitments under the CenterPoint Energy revolving credit facility increased to $3.3 billion on October 5, 2018 as a result of ~~December 31, 2015 and 2014, respectively.~~the satisfaction of certain conditions described above.


(6)	Issued by CERC Corp.

CenterPoint Energy’s $1.2 billion revolving credit facility, which is scheduled to terminate on September 9, 2019, can be drawn at the London Interbank Offered Rate (LIBOR) plus 1.25% based on CenterPoint Energy’s current credit ratings. The revolving credit facility contains a financial covenant which limits CenterPoint Energy’s consolidated debt (excluding transition and system restoration bonds) to an amount not to exceed 65% of CenterPoint Energy’s consolidated capitalization. As of December 31, 2015, CenterPoint Energy’s debt (excluding transition and system restoration bonds) to capital ratio, as defined in its credit facility agreement, was 55.1%. The financial covenant limit will temporarily increase from 65% to 70% if CenterPoint Houston experiences damage from a natural disaster in its service territory and CenterPoint Energy certifies to the administrative agent that CenterPoint Houston has incurred system restoration costs reasonably likely to exceed $100 million in a consecutive twelve-month period, all or part of which CenterPoint Houston 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.

~~111~~

CenterPoint Houston’s $300 million revolving credit facility, which is scheduled to terminate on September 9, 2019, can be drawn at LIBOR plus 1.125% based on CenterPoint Houston’s current credit ratings. The revolving credit facility contains a financial covenant which limits CenterPoint Houston’s consolidated debt (excluding transition and system restoration bonds) to an amount not to exceed 65% of CenterPoint Houston’s consolidated capitalization. As of December 31, 2015, CenterPoint Houston’s debt (excluding transition and system restoration bonds) to capital ratio, as defined in its credit facility agreement, was 51.7%.

CERC Corp.’s $600 million revolving credit facility, which is scheduled to terminate on September 9, 2019, can be drawn at LIBOR plus 1.50% based on CERC Corp.’s current credit ratings. The revolving credit facility contains a financial covenant which limits CERC’s consolidated debt to an amount not to exceed 65% of CERC’s consolidated capitalization. As of December 31, 2015, CERC’s debt to capital ratio, as defined in its credit facility agreement, was 33.9%.

~~CenterPoint Energy, CenterPoint Houston and CERC Corp.~~Registrants were in compliance with all financial debt covenants as of December 31, ~~2015~~.2018.

Maturities. ~~CenterPoint Energy’s~~As of December 31, 2018, maturities of long-term debt, capital leases and sinking fund requirements, excluding the ZENS obligation, are ~~$716 million~~ in ~~2016~~, ~~$911 million~~ in ~~2017, $1.1 billion in~~ ~~2018~~, ~~$1.6 billion~~ in ~~2019~~ ~~and~~ ~~$231 million~~ in ~~2020. These maturities include transition and system restoration bond principal repayments on scheduled payment dates aggregating~~ ~~$391 million~~ in ~~2016~~, ~~$411 million~~ in ~~2017~~, ~~$434 million~~ in ~~2018~~, ~~$458 million~~ in ~~2019~~ ~~and~~ ~~$231 million~~ in ~~2020~~.as follows:



	CenterPoint Energy (1)		Houston Electric (1)		CERC		Securitization Bonds
	(in millions)
2019	$	458	$	458	$	—	$	458
2020	231		231		—		231
2021	1,706		613		593		211
2022	1,230		519		210		219
2023	656		356		300		156


(1)	These maturities include Securitization Bonds principal repayments on scheduled payment dates.

Liens. As of December 31, ~~2015, CenterPoint Houston’s~~2018, Houston Electric’s assets were subject to liens securing approximately ~~$102~~$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 ~~2015~~, ~~2014~~2018, 2017 and ~~2013~~2016 have been satisfied by certification of property additions. The replacement fund requirement to be satisfied in ~~2016~~2019 is approximately ~~$223~~$283 million,, and the sinking fund requirement to be satisfied in ~~2016~~2019 is approximately $1.6 million. CenterPoint Energy expects ~~CenterPoint~~ Houston Electric to meet these ~~2016~~2019 obligations by certification of property additions.

As of December 31, ~~2015~~2018, ~~CenterPoint Houston’s~~Houston Electric’s assets were also subject to liens securing approximately $~~2.1~~3.3 billion of general mortgage bonds, including approximately $68 million held in trust to secure pollution control bonds for which ~~are~~CenterPoint Energy is obligated. The lien of the general mortgage indenture is junior to ~~the liens~~that of the mortgage pursuant to which the first mortgage ~~bonds.~~

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 $4.3 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, 2018. Houston Electric has contractually agreed that it will not issue additional first mortgage bonds, subject to certain exceptions.

~~(13)~~ (15) Income Taxes

The components of ~~CenterPoint Energy’s~~the Registrant’ income tax expense (benefit) were as follows:


	Year Ended December 31,									Year Ended December 31,
	2015			2014			2013			2018			2017			2016
	(in millions)									(in millions)
CenterPoint Energy
Current income tax expense:
Federal										$	89		$	32		$	23
State										9			9			18
Total current expense										98			41			41
Deferred income tax expense (benefit):
Federal										(25		)	(806		)	185
State										73			36			28
Total deferred expense (benefit)										48			(770		)	213
Total income tax expense (benefit)										$	146		$	(729	)	$	254
Houston Electric
Current income tax expense:
Federal										$	109		$	70		$	165
State										18			19			18
Total current expense										127			89			183
Deferred income tax benefit:
Federal										(38		)	(98		)	(34		)
Total deferred benefit										(38		)	(98		)	(34		)
Total income tax expense (benefit)										$	89		$	(9	)	$	149
CERC - Continuing Operations
Current income tax expense (benefit):
Federal	$	(37	)	$	(20	)	$	91		$	(9	)	$	(31	)	$	21
State	12			14			23			—			(10		)	4
Total current expense (benefit)	(25		)	(6		)	114			(9		)	(41		)	25
Deferred income tax expense (benefit):
Federal	(359		)	273			370			10			(249		)	41
State	(54		)	7			(14		)	21			25			15
Total deferred expense (benefit)	(413		)	280			356			31			(224		)	56
Total income tax expense (benefit)	$	(438	)	$	274		$	470		$	22		$	(265	)	$	81

~~112~~



	Year Ended December 31,
	2018		2017		2016
	(in millions)
CERC - Discontinued Operations
Current income tax expense (benefit):
Federal	$	9	$	31	$	(21	)
State	4		11		2
Total current expense (benefit)	13		42		(19		)
Deferred income tax expense:
Federal	29		56		90
State	4		6		10
Total deferred expense	33		62		100
Total income tax expense	$	46	$	104	$	81

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,									Year Ended December 31,
	2015			2014			2013			2018			2017			2016
	(in millions)									(in millions)
Income (loss) before income taxes	$	(1,130	)	$	885		$	781
CenterPoint Energy (1) (2) (3)
Income before income taxes										$	514		$	1,063		$	686
Federal statutory income tax rate	35.0		%	35.0		%	35.0		%	21		%	35		%	35		%
Expected federal income tax expense (benefit)	(396		)	310			273
Expected federal income tax expense										108			372			240
Increase (decrease) in tax expense resulting from:
State income tax expense, net of federal income tax	(27		)	16			21			22			26			27
Tax effect related to the formation of Enable	—			—			196
Decrease in settled and uncertain income tax positions	—			—			(9		)
Tax basis balance sheet adjustments	—			(29		)	—
State valuation allowance, net of federal income tax										11			3			3
State law change, net of federal income tax										32			—			—
Federal income tax rate reduction										—			(1,113		)	—
Excess deferred income tax amortization										(24		)	—			—
Other, net	(15		)	(23		)	(11		)	(3		)	(17		)	(16		)
Total	(42		)	(36		)	197			38			(1,101		)	14
Total income tax expense (benefit)	$	(438	)	$	274		$	470		$	146		$	(729	)	$	254
Effective tax rate	38.8		%	31.0		%	60.2		%	28		%	(69		)%	37		%
Houston Electric (4) (5)
Income before income taxes										$	425		$	424		$	425
Federal statutory income tax rate										21		%	35		%	35		%
Expected federal income tax expense										89			148			149
Increase (decrease) in tax expense resulting from:
State income tax expense, net of federal income tax										14			12			12
Federal income tax rate reduction										—			(158		)	—
Excess deferred income tax amortization										(9		)	—			—
Other, net										(5		)	(11		)	(12		)
Total										—			(157		)	—
Total income tax expense (benefit)										$	89		$	(9	)	$	149
Effective tax rate										21		%	(2		)%	35		%

In 2015, CenterPoint Energy’s effective tax rate was higher than the statutory rate primarily due to lower earnings from the impairment of CenterPoint Energy’s investment in Enable. The impairment loss reduced the deferred tax liability on CenterPoint Energy’s investment in Enable.



	Year Ended December 31,
	2018			2017			2016
	(in millions)
CERC - Continuing Operations (6) (7)
Income before income taxes	$	92		$	319		$	199
Federal statutory income tax rate	21		%	35		%	35		%
Expected federal income tax expense	19			112			70
Increase (decrease) in tax expense resulting from:
State income tax expense, net of federal income tax	5			6			4
State law change, net of federal income tax	—			—			6
State valuation allowance, net of federal income tax	11			3			2
Federal income tax rate reduction	—			(396		)	—
Excess deferred income tax amortization	(15		)	—			—
Tax basis balance sheet adjustment	—			11			—
Other, net	2			(1		)	(1		)
Total	3			(377		)	11
Total income tax expense (benefit)	$	22		$	(265	)	$	81
Effective tax rate	24		%	(83		)%	41		%
CERC - Discontinued Operations (7)
Income before income taxes	$	184		$	265		$	208
Federal statutory income tax rate	21		%	35		%	35		%
Expected federal income tax expense	39			93			73
Increase in tax expense resulting from:
State income tax expense, net of federal income tax	7			11			8
Total	7			11			8
Total income tax expense	$	46		$	104		$	81
Effective tax rate	25		%	39		%	39		%

(1)

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.


(2)	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%. For additional information on the 2017 impacts of the TCJA, please see the discussion following the deferred tax assets and liabilities table below.


(3)	Recognized a $6 million deferred tax expense in 2016 due to Louisiana state law change and recorded an additional $3 million valuation allowance on certain state carryforwards.


(4)	Recognized $9 million of amortization of the net regulatory EDIT liability as decreed by regulators in certain jurisdictions beginning in 2018.


(5)	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%. For additional information on the 2017 impacts of the TCJA, please see the discussion following the deferred tax assets and liabilities table below.

In 2014, CenterPoint Energy recognized a $29 million deferred income tax benefit upon completion of its tax basis balance sheet review. The adjustment resulted in a decrease to deferred tax liabilities of $32 million, a decrease to income taxes payable of $5 million and a decrease to income tax regulatory assets of $8 million. CenterPoint Energy determined the impact of the $29 million adjustment was not material to any prior period or the year ended December 31, 2014.


(6)	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.

In 2013, CenterPoint Energy recorded a deferred tax expense of $225 million at the formation of Enable related to the book-to-tax basis difference for contributed non-tax deductible goodwill and recognized a tax benefit of $29 million associated with the remeasurement of state deferred taxes at formation. In addition, CenterPoint Energy recognized a tax benefit of $8 million based on the settlement with the Internal Revenue Service (IRS) of outstanding tax claims for the 2002 and 2003 tax years.

(7)

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.

~~113~~

The tax effects of temporary differences that give rise to significant portions of deferred tax assets and liabilities were as follows:


	December 31,						December 31,
	2015			2014			2018			2017
	(in millions)						(in millions)
CenterPoint Energy
Deferred tax assets:
Benefits and compensation	$	334		$	347		$	160		$	162
Regulatory liabilities							356			347
Loss and credit carryforwards	115			69			84			90
Asset retirement obligations	73			65			62			68
Other	45			35			29			16
Valuation allowance	(2		)	(2		)	(18		)	(7		)
Total deferred tax assets	565			514			673			676
Deferred tax liabilities:
Property, plant, and equipment	2,423			2,126
Property, plant and equipment							1,894			1,808
Investment in unconsolidated affiliates	1,277			1,788			987			927
Regulatory assets/liabilities, net	1,060			1,225
Regulatory assets							395			473
Investment in marketable securities and indexed debt	654			636			478			502
Indexed debt securities derivative	91			65			27			13
Other	107			114			131			127
Total deferred tax liabilities	5,612			5,954			3,912			3,850
Net deferred tax liabilities	$	5,047		$	5,440		$	3,239		$	3,174
Houston Electric
Deferred tax assets:
Regulatory liabilities							$	205		$	198
Benefits and compensation							17			28
Asset retirement obligations							7			7
Other							12			3
Total deferred tax assets							241			236
Deferred tax liabilities:
Property, plant and equipment							1,087			1,030
Regulatory assets							177			265
Total deferred tax liabilities							1,264			1,295
Net deferred tax liabilities							$	1,023		$	1,059

~~Effective~~



	December 31,
	2018			2017
	(in millions)
CERC - Continuing Operations
Deferred tax assets:
Benefits and compensation	$	27		$	27
Regulatory liabilities	150			150
Loss and credit carryforwards	259			288
Asset retirement obligations	54			60
Other	20			18
Valuation allowance	(18		)	(7		)
Total deferred tax assets	492			536
Deferred tax liabilities:
Property, plant and equipment	773			745
Regulatory assets	41			38
Other	84			115
Total deferred tax liabilities	898			898
Net deferred tax liabilities	$	406		$	362
CERC - Discontinued Operations
Deferred tax liabilities:
Investment in unconsolidated affiliates	—			927
Net deferred tax liabilities	$	—		$	927

Federal Tax Reform

On December ~~31, 2015, all~~22, 2017, President Trump signed into law comprehensive tax reform legislation informally called the Tax Cuts and Jobs Acts, or TCJA, which resulted in significant changes to federal tax laws effective January 1, 2018. The new legislation contained several key tax provisions that impacted the Registrants, including the reduction of the corporate income tax rate from 35% to 21% effective January 1, 2018. The legislation also includes a variety of other changes, such as, a limitation on the tax deductibility of interest expense, acceleration of business asset expensing and reduction in the amount of executive pay that may qualify for a tax deduction, among others. Several other provisions of the TCJA were not generally applicable to the public utility industry, including the limitation on the tax deductibility of interest expense and the acceleration of business asset expensing.

While the effective date of the rate change in the legislation was January 1, 2018, ASC 740 requires that deferred tax balances be adjusted in the period of enactment to the rate in which those deferred taxes will reverse.

During 2017, CenterPoint Energy’s EDIT from the rate change resulted in an adjustment to income tax expense of approximately $1.1 billion and creation of a net regulatory liability of $1.3 billion (includes $0.3 billion gross-up) for ~~2014~~the amount that is likely to be returned to ratepayers. The major components of the $1.1 billion benefit to income tax expense are for the remeasurement of CenterPoint Energy's deferred taxes associated with its investment in Enable, investment in marketable securities (ZENS) and ~~2015~~stranded costs related to the Securitization Bonds.

During 2017, Houston Electric’s EDIT from the rate change resulted in an adjustment to income tax expense of $158 million and creation of a net regulatory liability of $829 million (includes $180 million gross-up) for the amount that is likely to be returned to ratepayers. The $158 million benefit to income tax expense is for the remeasurement of Houston Electric’s stranded costs related to the Securitization Bonds.

During 2017, CERC’s EDIT from the rate change resulted in an adjustment to income tax expense of $396 million and creation of a net regulatory liability of $478 million (includes $121 million gross-up) for the amount that is likely to be returned to ratepayers. The major components of the $396 million benefit to income tax expense were for the remeasurement of CERC’s deferred taxes associated with its investment in Enable and federal net operating loss carryforwards.

The amount and expected amortization of the net regulatory tax liability may differ from the Registrants’ estimates, possibly materially, due to, among other things, regulatory actions, interpretations and assumptions the Registrants have made, and any guidance that may be issued in the future. The Registrants will continue to assess the amount and expected amortization of the net regulatory tax liability as they have proceedings with regulators in future periods.

Houston Electric and CERC are ~~classified as noncurrent. See Note 2.~~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.

Tax Attribute Carryforwards and Valuation Allowance. ~~In 2015,~~ CenterPoint Energy has ~~a $44 million~~no remaining federal net operating loss carryforward ~~which expires in 2035, alternative minimum~~or federal tax credits as of ~~$9 million that carryover indefinitely, $17~~December 31, 2018. As of December 31, 2018, CenterPoint Energy had $802 million of ~~capital~~state net operating loss carryforwards that expire between 2019 and 2038 and $18 million of state tax credits that do not expire. CenterPoint Energy reported a valuation allowance of $18 million because it is more likely than not that the benefit from certain state net operating loss carryforwards will not be realized.

CERC has $951 million of federal net operating loss carryforwards which ~~expire between 2018 and 2019, $13 million~~have an indefinite carryforward period, however, utilization is limited to 80 percent of ~~charitable contribution carryforwards which expire between 2018 and 2020, and $5 million of general business credits which expire between 2030 and 2035.~~

~~CenterPoint Energy~~taxable income in any given taxable year. CERC has ~~$910~~$797 million of state net operating loss carryforwards which expire between ~~2016~~2019 and ~~2035, $7~~2038 and $17 million of state tax credits which do not ~~expire, and $244 million of state capital loss carryforwards which expire in 2017. Management has established~~expire. CERC reported a valuation allowance of $2$18 million ~~net of federal tax on~~since it is more likely than not that the benefit from certain state net operating ~~losses and the full amount of the state capital~~ loss ~~carryforwards. The valuation allowance was established based upon management’s evaluation that certain state~~ carryforwards ~~may~~will not be ~~fully~~ realized.

Uncertain Income Tax Positions. The ~~following table reconciles the beginning and ending balance of CenterPoint Energy’s unrecognized tax benefits (expenses):~~

December 31,
2015 2014 2013
(in millions)
Balance, beginning of year $ —
$ —
$ (23 )
Tax Positions related to prior years:

Reductions —
—
(1 )
Tax Positions related to current year:

Settlements —
—
24
Balance, end of year $ —
$ —
$ —

~~CenterPoint Energy~~Registrants reported no uncertain tax ~~liability~~liabilities as of December 31, ~~2015~~2018, 2017 and ~~expects~~2016. The Registrants expect no significant change to the uncertain tax ~~liability~~liabilities over the next ~~twelve~~12 months ending December 31, ~~2016 to have a material impact on financial position, results of operations and cash flows.~~

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CenterPoint Energy recognizes interest and penalties as a component of income tax expense. CenterPoint Energy recognized $3 million of income tax expense and $3 million of income tax benefit related to interest on income tax positions during 2014 and 2013, respectively. 2019.

Tax Audits and Settlements. Tax years through ~~2013~~2016 have been audited and settled with the IRS, however, during 2018 CenterPoint Energy filed an amended 2014 tax return to claim additional tax credits that is currently under review by the IRS. For the ~~2014~~2017 and ~~2015~~2018 tax years, ~~CenterPoint Energy is a participant~~the Registrants are participants in the IRS’s Compliance Assurance Process. ~~CenterPoint Energy has considered the effects of these examinations in its accrual for settled issues and liability for uncertain income tax positions (if any) as of December 31, 2015.~~

~~(14)~~ (16) Commitments and Contingencies

(a) Natural Gas Supply Commitments (CenterPoint Energy and CERC)

Natural gas supply commitments include natural gas contracts related to CenterPoint Energy’s and CERC’s Natural Gas Distribution and Energy Services ~~business~~reportable segments, which have various quantity requirements and durations, that are not classified as non-trading derivative assets and liabilities in CenterPoint Energy’s and CERC’s Consolidated Balance Sheets as of December 31, ~~2015~~2018 and ~~2014~~2017 as these contracts meet an exception as “normal purchases contracts” or do not meet the definition of a derivative. Natural gas supply commitments also include natural gas transportation contracts that do not meet the definition of a derivative.

As of December 31, ~~2015~~2018, minimum payment obligations for natural gas supply commitments are ~~approximately~~ approximately:~~$478 million~~ in ~~2016~~, ~~$457 million~~ in ~~2017~~, ~~$405 million~~ in ~~2018~~, ~~$217 million~~ in ~~2019~~, ~~$90 million~~ in ~~2020~~ ~~and~~ ~~$38 million~~ ~~after~~ ~~2020~~.




	(in millions)
2019	$	454
2020	430
2021	343
2022	231
2023	154
2024 and beyond	1,446

(b) ~~Asset Management Agreements~~AMAs (CenterPoint Energy and CERC)

NGD has ~~asset management agreements (AMAs)~~AMAs associated with its utility distribution service in Arkansas, Louisiana, Mississippi, Oklahoma and Texas. In March 2018, NGD’s third party AMAs in Arkansas, Louisiana and Oklahoma expired, and NGD entered into new AMAs with CES effective April 1, 2018 in these states. The AMAs have varying terms, the longest of which expires in 2021. Pursuant to the provisions of the agreements, NGD sells natural gas and agrees to repurchase an equivalent amount of natural gas during the winter heating seasons at the same cost. Generally, ~~these~~ AMAs are contracts between NGD and an asset manager that are intended to transfer the working capital obligation and maximize the utilization of the assets. In these AMAs, NGD ~~agreed~~agrees to release transportation and storage capacity to other parties to manage natural gas storage, supply and delivery arrangements for NGD and to use the released capacity for other purposes when it is not needed for NGD. NGD is compensated by the asset manager through payments

made over the life of the ~~AMAs based in part on the results of the asset optimization.~~AMAs. NGD has an obligation to purchase its winter storage requirements that have been released to the asset manager under these AMAs. ~~The AMAs have varying terms, the longest of which expires in 2019.~~

The following table sets forth information concerning ~~CenterPoint Energy’s~~the Registrants’ obligations under non-cancelable long-term operating leases as of December 31, ~~2015~~2018, which primarily consist of rental agreements for ~~building space, data processing equipment, compression equipment and rights-of-way:~~real property:

(in millions)
2016 $ 5
2017 4
2018 3
2019 3
2020 2
2021 and beyond 7
Total $ 24



	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	$	36	$	1	$	32

~~Total lease expense for all operating leases was~~ ~~$9 million~~, ~~$11 million~~ ~~and~~ ~~$21 million~~ ~~during~~ ~~2015~~, ~~2014~~ ~~and~~ ~~2013, respectively.~~



	Year Ended December 31,
	2018						2017						2016
	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC
	(in millions)
Lease expense	$	9	$	1	$	8	$	10	$	1	$	9	$	10	$	1	$	9

(d) Legal, Environmental and Other ~~Regulatory~~ Matters

Legal Matters (CenterPoint Energy and CERC)

Gas Market Manipulation Cases. CenterPoint Energy, ~~CenterPoint Houston or their~~its predecessor, Reliant Energy, ~~Incorporated (Reliant Energy),~~ and certain of their former subsidiaries ~~have been~~were named as defendants in ~~certain~~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 pending in federal court in Nevada in which CES, a subsidiary of CERC Corp., is a defendant. Plaintiffs in that case allege a conspiracy to inflate Wisconsin natural gas prices in 2000-2002. In May 2016, the district court granted CES’s motion for summary judgment, dismissing CES from the case. In August 2018, the Ninth Circuit Court of Appeals reversed that ruling, and CES requested further appellate review of that decision (which review has been stayed pending approval of the settlement agreement described ~~below.~~ below).

Under a master separation agreement between CenterPoint Energy and a former subsidiary, ~~Reliant Resources, Inc. (RRI),~~

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RRI, CenterPoint Energy and its subsidiaries are entitled to be indemnified by RRI and its successors for any losses, including certain attorneys’ fees and other costs, arising out of these lawsuits. ~~In May 2009,~~Through a series of transactions, RRI ~~sold its Texas retail business to a subsidiary of NRG~~became known as GenOn and RRI changed its name to RRI Energy, Inc. In December 2010, Mirant Corporation merged with and became a wholly-owned subsidiary of RRI, and RRI changed its name to GenOn Energy, Inc. (GenOn). In December 2012, NRG acquired GenOn through a merger in which GenOn became a wholly-owned subsidiary of NRG. None of ~~the sale of the retail business, the merger with Mirant Corporation, or the acquisition of GenOn by NRG~~those transactions alters ~~RRI’s (now GenOn’s)~~GenOn’s contractual obligations to indemnify CenterPoint Energy and its subsidiaries ~~including CenterPoint Houston,~~ for certain liabilities, including their indemnification obligations regarding the gas market manipulation ~~litigation, nor does it affect the terms of existing guarantee arrangements~~litigation. In June 2017, however, GenOn and various affiliates filed for ~~certain GenOn gas transportation contracts discussed below.~~

~~A large number of lawsuits were filed against numerous gas market participants in a number of federal and western state courts in connection with the operation~~protection under Chapter 11 of the ~~natural gas markets in 2000–2002.~~U.S. Bankruptcy Code. In December 2018, GenOn completed its reorganization and emerged from Chapter 11. CenterPoint Energy, CERC, and ~~its affiliates have since been released or dismissed from~~CES submitted proofs of claim in the bankruptcy proceedings to protect their indemnity rights. In October 2018, CES, GenOn, and the plaintiffs reached an agreement to settle all but one such case. CenterPoint Energy Services, Inc. (CES), a subsidiary of CERC Corp., is a defendant in a case now pending in federal court in Nevada alleging a conspiracy to inflate Wisconsin natural gas prices in 2000–2002. In July 2011, the court issued an order dismissing the plaintiffs’ claims against ~~other defendants in~~CES and CES’s indemnity claims against GenOn, subject to approvals by the ~~case, each of whom had demonstrated Federal Energy Regulatory Commission jurisdictional sales for resale during~~bankruptcy court and the ~~relevant period, based on~~ federal ~~preemption,~~district court. In January 2019, the bankruptcy court approved the settlement between CES and ~~stayed~~GenOn. If the ~~remainder of~~settlement agreement between CES, GenOn and the ~~case pending outcome of~~plaintiffs is not approved by the appeals. The plaintiffs appealed this ruling to the U.S. Court of Appeals for the Ninth Circuit, which reversed the trial court’s dismissal of the plaintiffs’ claims. On April 21, 2015, the U.S. Supreme Court affirmed the Ninth Circuit’s ruling and remanded the case to thefederal district court, CES could incur liability and be responsible for ~~further proceedings, which are now underway. CenterPoint Energy and CES intend to continue vigorously defending against the plaintiffs’ claims.~~satisfying it. 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.

Minnehaha Academy. On August 2, 2017, a natural gas explosion occurred at the Minnehaha Academy in Minneapolis, Minnesota, resulting in the deaths of two school employees, serious injuries to others and significant property damage to the school. CenterPoint Energy, certain of its subsidiaries, 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 with some claimants. Additionally, CenterPoint Energy and CERC are cooperating with the ongoing investigation conducted by

the National Transportation Safety Board. Further, CenterPoint Energy and CERC are contesting approximately $200,000 in fines imposed by the Minnesota Office of Pipeline Safety. In early 2018, the Minnesota Occupational Safety and Health Administration concluded its investigation without any adverse findings against CenterPoint Energy 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.

Environmental Matters

~~Manufactured Gas Plant Sites.~~MGP Sites(CenterPoint Energy and CERC). CenterPoint Energy, CERC and its predecessors operated ~~manufactured gas plants (MGPs)~~MGPs in the past. With respect to certain Minnesota MGP sites, CenterPoint Energy and CERC ~~has~~have completed state-ordered remediation and ~~continues~~continue state-ordered monitoring and water treatment. As of December 31, ~~2015,~~2018, CenterPoint Energy and CERC had a recorded liability of $7 million for continued monitoring and any future remediation required by regulators in Minnesota. The estimated range of possible remediation costs for the sites for which CenterPoint Energy and CERC ~~believes it~~believe they may have responsibility was $5 million to ~~$29~~$32 million based on remediation continuing for 30 to 50 years. 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 ~~potentially responsible parties (PRPs),~~PRPs, if any, and the remediation methods used.

In addition to the Minnesota sites, the ~~Environmental Protection Agency~~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 ~~its~~their former affiliates. CenterPoint Energy ~~does~~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 ~~CenterPoint Energy~~the Registrants or their predecessors in interest contain or have contained asbestos insulation and other asbestos-containing materials. ~~CenterPoint Energy or its subsidiaries have been~~The Registrants are from time to time named, along with numerous others, as ~~a defendant~~defendants in lawsuits filed by a number of individuals who claim injury due to exposure to ~~asbestos. Some of~~asbestos, and the claimants have worked at locations owned by subsidiaries of CenterPoint Energy, but most existing claims relate to facilities previously owned by CenterPoint Energy’s subsidiaries. In 2004 and early 2005, CenterPoint Energy sold its generating business, to which most of these claims relate, to a company which is now an affiliate of NRG. Under the terms of the arrangements regarding separation of the generating business from CenterPoint Energy and its sale of that business, ultimate financial responsibility for uninsured losses from claims relating to the generating business has been assumed by the NRG affiliate, but 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 the NRG affiliate. CenterPoint Energy anticipatesRegistrants anticipate that additional claims ~~like those received~~ may be asserted in the future. Although their ultimate outcome cannot be predicted at this time, ~~CenterPoint Energy intends to continue vigorously contesting claims that it does not consider to have merit and, based on its experience to date, does~~the Registrants do not expect these matters, either individually or in the aggregate, to have a material adverse effect on ~~CenterPoint Energy’s~~their financial condition, results of operations or cash flows.

Other Environmental. From time to time, ~~CenterPoint Energy identifies~~the Registrants identify the presence of environmental contaminants during operations or on property where ~~its subsidiaries conduct or~~predecessor companies have conducted operations. Other such sites involving contaminants may be identified in the future. ~~CenterPoint Energy has~~The Registrants have and ~~expects~~expect to continue to remediate any identified sites consistent with ~~its~~state and federal legal obligations. From time to time, ~~CenterPoint Energy has~~the Registrants have received notices, and may receive notices in the future, from regulatory authorities or others regarding ~~its~~ status as a PRP in connection with sites found to require remediation due to the presence of environmental contaminants. In addition, ~~CenterPoint Energy has~~

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the Registrants have been, or may be, named from time to time as ~~a defendant~~defendants in litigation related to such sites. Although the ultimate outcome of such matters cannot be predicted at this time, ~~CenterPoint Energy does~~the Registrants do not expect ~~based on its experience to date,~~ these matters, either individually or in the aggregate, to have a material adverse effect on ~~CenterPoint Energy’s~~their financial condition, results of operations or cash flows.

Other Proceedings

~~CenterPoint Energy is~~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, ~~CenterPoint Energy is~~the Registrants are also ~~a defendant~~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. ~~CenterPoint Energy~~The Registrants regularly ~~analyzes~~analyze current information and, as necessary, ~~provides~~provide accruals for probable and reasonably estimable liabilities on the eventual disposition of these matters. ~~CenterPoint Energy does~~The Registrants do not expect the disposition of these matters to have a material adverse effect on ~~CenterPoint Energy’s~~the Registrants’ financial condition, results of operations or cash flows.

~~(e) Guarantees~~

Prior to the distribution of CenterPoint Energy’s ownership in RRI to its shareholders, CERC had guaranteed certain contractual obligations of what became RRI’s trading subsidiary. When the companies separated, RRI agreed to secure CERC against obligations under the guarantees RRI had been unable to extinguish by the time of separation. Pursuant to such agreement, as amended in December 2007, RRI (now GenOn) agreed to provide to CERC cash or letters of credit as security against CERC’s obligations under its remaining guarantees for demand charges under certain gas transportation agreements if and to the extent changes in market conditions expose CERC to a risk of loss on those guarantees based on an annual calculation, with any required collateral to be posted each December. The undiscounted maximum potential payout of the demand charges under these transportation contracts, which will be in effect until 2018, was approximately $27 million as of ~~December 31, 2015~~. Based on market conditions in the fourth quarter of 2015 at the time the most recent annual calculation was made under the agreement, GenOn was not obligated to post any security. If GenOn should fail to perform the contractual obligations, CERC could have to honor its guarantee and, in such event, any collateral then provided as security may be insufficient to satisfy CERC’s obligations.

CERC Corp. has also provided a guarantee of collection of $1.1 billion of Enable’s Guaranteed Senior Notes. This guarantee is subordinated to all senior debt of CERC Corp. and is subject to automatic release on May 1, 2016.

~~The fair value of these guarantees is not material.~~

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~~(15)~~ (17) Earnings Per Share(CenterPoint Energy)

The following table reconciles numerators and denominators of CenterPoint Energy’s basic and diluted earnings ~~(loss)~~ per common share. Basic earnings per common share ~~calculations:~~is determined by dividing Income available to common shareholders - basic by the Weighted average common shares outstanding - basic for the applicable period. Diluted earnings per common share is determined by the inclusion of potentially dilutive common stock equivalent shares that may occur if securities to issue Common Stock were exercised or converted into Common Stock.

For the Year Ended December 31,
2015 2014 2013
(in millions, except per share and share amounts)
Net income (loss) $ (692 ) $ 611
$ 311

Basic weighted average shares outstanding 430,180,000
429,634,000
428,466,000
Plus: Incremental shares from assumed conversions:

Stock options —
—
41,000
Restricted stock (1) —
2,034,000
2,423,000
Diluted weighted average shares 430,180,000
431,668,000
430,930,000

Basic earnings (loss) per share $ (1.61 ) $ 1.42
$ 0.73

Diluted earnings (loss) per share $ (1.61 ) $ 1.42
$ 0.72



	For the Year Ended December 31,
	2018		2017		2016
	(in millions, except per share and share amounts)
Numerator:
Income available to common shareholders - basic (1)	$	333	$	1,792	$	432
Add back: Series B Preferred Stock dividend	—		—		—
Income available to common shareholders - diluted (1)	$	333	$	1,792	$	432

Denominator:
Weighted average common shares outstanding - basic	448,829,000		430,964,000		430,606,000
Plus: Incremental shares from assumed conversions:
Restricted stock (2)	3,636,000		3,344,000		2,997,000
Series B Preferred Stock (3)	—		—		—
Weighted average common shares outstanding - diluted	452,465,000		434,308,000		433,603,000

Earnings per common share:
Basic earnings per common share	$	0.74	$	4.16	$	1.00
Diluted earnings per common share	$	0.74	$	4.13	$	1.00


(1)	~~2,349,000 incremental shares from assumed conversions of restricted stock have not been included in the computation of diluted earnings (loss) per share~~Income available to common shareholders for the year ended December 31, ~~2015,~~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 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.

(3)

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 ~~their inclusion~~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, 2018 excludes 8,885,000 potentially dilutive shares because to include them would be anti-dilutive. However, these shares could be potentially dilutive in the future.

~~(16)~~ (18) Unaudited Quarterly Information

Summarized quarterly financial data is as follows:

Year Ended December 31, 2015

First
Quarter

Second
Quarter

Third
Quarter (2)

Fourth
Quarter (3)
(in millions, except per share amounts)
Revenues $ 2,433
$ 1,532
$ 1,630
$ 1,791
Operating income 256
186
265
226
Net income (loss) 131
77
(391 ) (509 )

Basic earnings (loss) per share (1) $ 0.30
$ 0.18
$ (0.91 ) $ (1.18 )

Diluted earnings (loss) per share (1) $ 0.30
$ 0.18
$ (0.91 ) $ (1.18 )



	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


	Year Ended December 31, 2014								Year Ended December 31, 2018
	First Quarter		Second Quarter		Third Quarter		Fourth Quarter (4)		First Quarter	Second Quarter		Third Quarter		Fourth Quarter
	(in millions, except per share amounts)								(in millions, except per share amounts)
Houston Electric
Revenues	$	3,163	$	1,884	$	1,807	$	2,372	755	854		897		728
Operating income	295		186		233		221		119	181		227		98
Net income	185		107		143		176		52	101		143		40

Basic earnings per share (1)	$	0.43	$	0.25	$	0.33	$	0.41

Diluted earnings per share (1)	$	0.43	$	0.25	$	0.33	$	0.41
CERC (4)
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



	Year Ended December 31, 2017
	First Quarter		Second Quarter		Third Quarter			Fourth Quarter
	(in millions, except per share amounts)
CenterPoint Energy
Revenues	$	2,735	$	2,143	$	2,098		$	2,638
Operating income (2)	291		240		297			308
Income available to common shareholders (3)	192		135		169			1,296
Basic earnings per common share (1)	0.45		0.31		0.39			3.01
Diluted earnings per common share (1)	0.44		0.31		0.39			2.99
Houston Electric
Revenues	638		752		843			765
Operating income (2)	85		171		254			127
Net income (3)	18		75		130			210
CERC (4)
Revenues	2,093		1,387		1,251			1,872
Operating income (2)	199		59		31			178
Income (loss) from continuing operations	102		17		(4		)	469
Income from discontinued operations	45		37		42			37
Net income (3)	147		54		38			506


(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.

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(2)	~~CenterPoint Energy recognized $862 million ($537 million after tax) in impairment charges related~~Recast to ~~Enable during~~reflect the ~~three months ended September 30, 2015.~~adoption of ASU 2017-07. See Note 2(r) for further information.

(3)

Income available to common shareholders and Net income for the fourth quarter 2017 include a reduction in income tax expense of $1,113 million, $158 million and $396 million for CenterPoint Energy, ~~recognized $984 million ($620 million after tax) in impairment charges related~~Houston Electric and CERC, respectively, due to ~~Enable during~~ the ~~three months ended December 31, 2015.~~TCJA. See Note 15 for further discussion of the impacts of tax reform implementation.


(4)	~~CenterPoint Energy recognized a $29 million deferred income tax benefit upon completion of its tax basis balance sheet review.~~ Amounts have been recast to reflect discontinued operations in all periods presented.

~~(17)~~ (19) Reportable ~~Business~~ Segments

~~CenterPoint Energy’s~~The Registrants’ determination of reportable ~~business~~ segments considers the strategic operating units under which ~~CenterPoint Energy manages~~the Registrants manage sales, ~~allocates~~allocate resources and ~~assesses~~assess performance of various products and services to wholesale or retail customers in differing regulatory environments. ~~CenterPoint Energy uses~~The Registrants use operating income as the measure of profit or loss for ~~its business segments.~~the reportable segments other than Midstream Investments, where equity in earnings is used.

~~CenterPoint Energy’s~~

As of December 31, 2018, reportable ~~business~~ segments ~~include the following:~~ by Registrant are as follows:



	Electric Transmission & Distribution	Natural Gas Distribution	Energy Services	Midstream Investments	Other Operations
CenterPoint Energy	X	X	X	X	X
Houston Electric	X
CERC		X	X	(1)	X

(1)

On September 4, 2018, CERC completed the Internal Spin. Previously, CERC’s equity method investment in Enable was included in CERC’s Midstream Investments reportable segment. CERC’s equity in earnings in Enable, net of basis difference amortization and income tax, have been classified as discontinued operations for all periods presented. See Note 11 for further discussion on the Internal Spin and the associated discontinued operations presentation.

Electric Transmission & Distribution ~~Natural Gas Distribution, Energy Services, Midstream Investments and Other Operations. The~~consists of the electric transmission and distribution ~~function (CenterPoint Houston) is reported in the Electric Transmission & Distribution business segment.~~function. Natural Gas Distribution consists of intrastate natural gas sales to, and natural gas transportation and distribution for, residential, commercial, industrial and institutional customers. Energy Services ~~represents CenterPoint Energy’s~~consists of non-rate regulated natural gas sales and services operations. Midstream Investments consists of ~~CenterPoint Energy’s~~the equity investment in ~~Enable.~~Enable (excluding the Enable Series A Preferred Units). Other Operations consists primarily of other corporate operations which support all of ~~CenterPoint Energy’s~~the business operations.

~~Prior~~Houston Electric consists of a single reportable segment, Electric Transmission & Distribution, and therefore is not included in the tabular reportable segment presentation below.

Operating income (loss) amounts for 2017 and 2016 have been recast to May 1, 2013, CenterPoint Energy also reported an Interstate Pipelines business segment, which included CenterPoint Energy’s interstate natural gas pipeline operations, and a Field Services business segment, which included CenterPoint Energy’s non-rate regulated natural gas gathering, processing and treating operations. The formationreflect the adoption of Enable closed on May 1, 2013. Enable now owns substantially all of CenterPoint Energy’s former Interstate Pipelines and Field Services business segments. As a result, effective May 1, 2013, CenterPoint Energy reports equity earnings associated with its interest in Enable under its Midstream Investments segment, and no longer has Interstate Pipelines and Field Services reporting segments prospectively.ASU 2017-07 (see Note 2(r) for further information).

Long-lived assets include net property, plant and equipment, goodwill and other intangibles and equity investments in unconsolidated subsidiaries. Intersegment sales are eliminated in consolidation.

~~119~~

Financial data for ~~business~~reportable segments and products and services are as follows:

CenterPoint Energy


	Revenues from External Customers			Intersegment Revenues			Depreciation and Amortization		Operating Income (Loss)			Total Assets				Expenditures for Long-Lived Assets		Revenues from External Customers			Intersegment Revenues			Depreciation and Amortization		Operating Income			Total Assets				Expenditures for Long-Lived Assets
	(in millions)																	(in millions)
As of and for the year ended December 31, 2015:
As of and for the year ended December 31, 2018:
Electric Transmission & Distribution	$	2,845	(1)	$	—		$	705	$	607		$	10,049			$	934	$	3,232	(1)	$	—		$	917	$	623		$	10,509			$	952
Natural Gas Distribution	2,603			29			222		273			5,657				601		2,931			36			277		266			6,956				638
Energy Services	1,924			33			5		42			857				5		4,411			110			16		(47		)	1,558				20
Midstream Investments (2)	—			—			—		—			2,594				—		—			—			—		—			2,482				—
Other	14			—			38		11			2,902			(3)	35
Reconciling Eliminations	—			(62		)	—		—			(725		)		—
Other Operations																		15			—			33		(11		)	6,156			(3)	110
Eliminations																		—			(146		)	—		—			(652		)		—
Consolidated	$	7,386		$	—		$	970	$	933		$	21,334			$	1,575	$	10,589		$	—		$	1,243	$	831		$	27,009			1,720
As of and for the year ended December 31, 2014:
Electric Transmission & Distribution	$	2,845	(1)	$	—		$	768	$	595		$	10,066			$	818
Natural Gas Distribution	3,271			30			201		287			5,464				525
Energy Services	3,095			84			5		52			978				3
Midstream Investments (2)	—			—			—		—			4,521				—
Other	15			—			39		1			3,368			(3)	56
Reconciling Eliminations	—			(114		)	—		—			(1,197		)		—
Consolidated	$	9,226		$	—		$	1,013	$	935		$	23,200			$	1,402
As of and for the year ended December 31, 2013:
Electric Transmission & Distribution	$	2,570	(1)	$	—		$	685	$	607		$	9,605			$	759
Natural Gas Distribution	2,837			26			185		263			4,976				430
Energy Services	2,374			27			5		13			895				3
Interstate Pipelines (4) (5)	133			53			20		72			—				29
Field Services (5)	178			18			20		73			—				16
Midstream Investments (2)	—			—			—		—			4,518				—
Other	14			—			39		(18		)	3,026			(3)	35
Reconciling Eliminations	—			(124		)	—		—			(1,150		)		—
Consolidated	$	8,106		$	—		$	954	$	1,010		$	21,870			$	1,272
Reconciling items																																	(69		)
Capital expenditures per Statements of Consolidated Cash Flows																																	$	1,651



	Revenues from External Customers			Intersegment Revenues			Depreciation and Amortization		Operating Income		Total Assets				Expenditures for Long-Lived Assets
	(in millions)
As of and for the year ended December 31, 2017:
Electric Transmission & Distribution	$	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 (2)	—			—			—		—		2,472				—
Other Operations	14			—			33		26		2,497			(3)	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
As of and for the year ended December 31, 2016:
Electric Transmission & Distribution	$	3,060	(1)	$	—		$	838	$	653	$	10,211			$	858
Natural Gas Distribution	2,380			29			242		321		6,099				510
Energy Services	2,073			26			7		21		1,102				5
Midstream Investments (2)	—			—			—		—		2,505				—
Other Operations	15			—			39		28		2,681			(3)	33
Eliminations	—			(55		)	—		—		(769		)		—
Consolidated	$	7,528		$	—		$	1,126	$	1,023	$	21,829			1,406
Reconciling items															8
Capital expenditures per Statements of Consolidated Cash Flows															$	1,414


(1)	CenterPoint ~~Houston’s transmission~~Energy’s and ~~distribution~~Houston Electric’s Electric Transmission & Distribution revenues from major customers are as follows:


	Year Ended December 31, 2015						Year Ended December 31,
	2015		2014		2013		2018		2017		2016
	(in millions)						(in millions)
Affiliates of NRG	$	741	$	735	$	658	$	705	$	713	$	698
Affiliates of Energy Future Holdings Corp.	220		189		167
Affiliates of Vistra Energy Corp.							251		229		220


(2)	CenterPoint Energy’s Midstream Investments’ equity earnings, ~~(losses)~~net are as follows:

Year Ended December 31, 2015
2015 2014 2013
(in millions)
Enable (1) $ (1,633 ) $ 303
$ 173
SESH —
5
8
Total $ (1,633 )
$ 308

$ 181

~~120~~


~~(1)~~	These amounts include CenterPoint Energy’s share of Enable’s impairment of goodwill and long-lived assets and the impairment of CenterPoint Energy’s equity method investment in Enable totaling $1,846 million during the year ended December 31, 2015. This impairment is offset by $213 million of earnings for the year ended December 31, 2015.

~~Midstream Investments’ total assets are as follows:~~

December 31,
2015 2014
(in millions)
Enable $ 2,594
$ 4,520
SESH —
1
Total $ 2,594
$ 4,521



	Year Ended December 31,
	2018		2017		2016
	(in millions)
Enable	$	307	$	265	$	208

(3)

~~Included in total~~Total assets ~~of Other Operations as of~~ ~~December 31, 2015~~, ~~2014~~ ~~and~~ ~~2013, are~~included pension and other ~~postemployment related~~postemployment-related regulatory assets of $~~814~~665 million, $~~795~~600 million and $~~627~~759 million, as of December 31, 2018, 2017 and 2016, 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.

CERC



	Revenues from External Customers		Intersegment Revenues			Depreciation and Amortization		Operating Income			Total Assets (1)				Expenditures for Long-Lived Assets
	(in millions)
As of and for the year ended December 31, 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
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
As of and for the year ended December 31, 2016:
Natural Gas Distribution	$	2,380	$	29		$	242	$	321		$	6,099			$	510
Energy Services	2,073		26			7		21			1,102				5
Discontinued operations	—		—			—		—			2,505			(1)	—
Other Operations	1		—			—		(1		)	75				—
Eliminations	—		(55		)	—		—			(563		)		—
Consolidated	$	4,454	$	—		$	249	$	341		$	9,218			515
Reconciling items															2
Capital expenditures per Statements of Consolidated Cash Flows															$	517


(1)	On September 4, 2018, CERC completed the Internal Spin. For further information regarding the Internal Spin, see Note 11.



	Year Ended December 31,
	2018						2017						2016
Revenues by Products and Services:	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC
	(in millions)
Electric delivery	$	3,232	$	3,234	$	—	$	2,997	$	2,998	$	—	$	3,060	$	3,059	$	—
Retail gas sales	4,161		—		4,161		3,634		—		3,634		3,329		—		3,329
Wholesale gas sales	3,008		—		3,008		2,811		—		2,811		977		—		977
Gas transportation and processing	32		—		32		29		—		29		23		—		23
Energy products and services	156		—		142		143		—		129		139		—		125
Total	$	10,589	$	3,234	$	7,343	$	9,614	$	2,998	$	6,603	$	7,528	$	3,059	$	4,454

(20) Supplemental Disclosure of Cash Flow Information

The tables below provide supplemental disclosure of cash flow information:



	2018						2017						2016
	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	$	363	$	200	$	105	$	378	$	205	$	116	$	406		$	209	$	116
Income taxes (refunds), net	89		154		3		15		76		4		(104		)	128		3
Non-cash transactions:
Accounts payable related to capital expenditures	201		124		80		144		104		56		87			65		35
Capital distribution associated with the Internal Spin	—		—		1,473		—		—		—		—			—		—

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, 2018						December 31, 2017
	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC
	(in millions)
Cash and cash equivalents (1) (2)	$	4,231	$	335	$	14	$	260	$	238	$	12
Restricted cash included in Prepaid expenses and other current assets	46		34		11		35		35		—
Restricted cash included in Other	1		1		—		1		1		—
Total cash, cash equivalents and restricted cash shown in Statements of Consolidated Cash Flows	$	4,278	$	370	$	25	$	296	$	274	$	12

(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 $28 million, $2 million and $1 million for the years ended December 31, 2018, 2017 and 2016, 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.

~~(4)~~(2)

~~Interstate Pipelines~~Houston Electric’s Cash and cash equivalents as of December 31, 2018 and 2017 included $335 million and $230 million, respectively, of cash related to the Bond Companies. Houston Electric recorded ~~equity~~interest income of $7$4 million, in $2 million and $1 million for the ~~year~~years ended December 31, ~~2013~~ ~~from its interest~~2018, 2017 and 2016, respectively, in ~~SESH, a jointly-owned pipeline. These amounts are included in Equity in earnings~~Other, net on Houston Electric’s Statement of unconsolidated affiliates under the Other Income (Expense) caption. As discussed above, effective May 1, 2013, CenterPoint Energy reports equity earnings associated with its interest in Enable and equity earnings associated with its interest in SESH under its Midstream Investments segment, and no longer has an Interstate Pipelines reporting segment prospectively.

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, 2018						December 31, 2017
	Houston Electric			CERC			Houston Electric			CERC
	(in millions)
Money pool investments (borrowings) (1)	$	(1	)	$	114		$	(60	)	$	(570	)
Weighted average interest rate	2.42		%	2.42		%	1.90		%	1.90		%


~~(5)~~(1)	~~Results reflected~~Included in ~~the year ended December 31, 2013 represent only January 2013 through April 2013.~~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,
Revenues by Products and Services: 2015 2014 2013
(in millions)
Electric delivery $ 2,845
$ 2,845
$ 2,570
Retail gas sales 3,725
5,049
4,150
Wholesale gas sales 657
1,159
913
Gas transportation and processing 26
38
345
Energy products and services 133
135
128
Total $ 7,386
$ 9,226
$ 8,106



	Year Ended December 31,
	2018				2017				2016
	Houston Electric		CERC		Houston Electric		CERC		Houston Electric			CERC
	(in millions)
Interest income (expense), net (1)	$	1	$	—	$	2	$	—	$	(4	)	$	—


(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.

Amounts charged for these services were as follows and are included primarily in operation and maintenance expenses:



	Year Ended December 31,
	2018					2017					2016
	Houston Electric			CERC		Houston Electric			CERC		Houston Electric			CERC
	(in millions)
Corporate service charges	$	190		$	147	$	188		$	128	$	179		$	125
Net affiliate service charges (billings)	(17		)	17		(9		)	9		(8		)	8

The table below presents transactions among Houston Electric, CERC and their parent, Utility Holding.



	Year Ended December 31,
	2018				2017				2016
	Houston Electric		CERC		Houston Electric		CERC		Houston Electric		CERC
	(in millions)
Cash dividends paid to parent	$	209	$	360	$	180	$	601	$	135	$	643
Cash contribution from parent	200		960		—		38		374		72
Capital distribution to parent associated with the Internal Spin	—		1,473		—		—		—		—

~~(18)~~ (22) Subsequent Events

On ~~January 20, 2016, CenterPoint Energy’s board of directors declared a regular quarterly cash dividend of~~ ~~$0.2575~~ ~~per share of common stock payable on~~ ~~March 10, 2016, to shareholders of record as of the close of business on~~ ~~February 16, 2016~~.Enable Distributions Declarations (CenterPoint Energy)

Equity Instrument

Declaration Date

Record Date

Payment Date

Per Unit Distribution

Expected Cash Distribution

(in millions)

Common units

February 8, 2019

February 19, 2019

February 26, 2019

0.318

Enable Series A Preferred Units

February 8, 2019

February 14, 2019

0.625

On January 22, 2016, Enable declared a quarterly cash distribution of $0.318 per unit on all of its outstanding common and subordinated units for the quarter ended December 31, 2015. Accordingly, CERC Corp. expects to receive a cash distribution of approximately $74 million from Enable in the first quarter of 2016 to be made with respect to CERC Corp.’s limited partner interest in Enable for the fourth quarter of 2015.

On January 28, 2016, CenterPoint Energy entered into a purchase agreement with Enable pursuant to which it agreed to purchase in a private placement (Private Placement) an aggregate of 14,520,000 10% Series A Fixed-to-Floating Non-Cumulative Redeemable Perpetual Preferred Units representing limited partner interests in Enable (Series A Preferred Units) for a cash purchase price of $25.00 per Series A Preferred Unit. The Private Placement closed on February 18, 2016. In connection with the Private Placement, Enable redeemed approximately $363 million of notes scheduled to mature in 2017 payable to a wholly-owned subsidiary of CERC Corp. CenterPoint Energy used the proceeds from this redemption for its investment in the Series A Preferred Units.

On January 29, 2016, CenterPoint Energy Services, an indirect subsidiary of CenterPoint Energy, announced an agreement to acquire the retail commercial and industrial businesses of Continuum Energy Services, a Tulsa and Houston-based company, for $77.5 million plus working capital. The transaction is conditioned upon the receipt of certain third party consents and approvals. CenterPoint Energy expects the transaction to close by the end of the first quarter of 2016.

~~121~~


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, wethe Registrants carried out ~~an evaluation,~~separate evaluations, under the supervision and with the participation of each company’s management, including ~~our~~the principal executive officer and principal financial officer, of the effectiveness of ~~our~~the disclosure controls and procedures as of the end of the period covered by this report. Based on ~~that evaluation, our~~those evaluations, the principal executive officer and principal financial officer, in each case, concluded that ~~our~~the disclosure controls and procedures were effective as of December 31, ~~2015~~2018 to provide assurance that information required to be disclosed in ~~our~~the reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the ~~Securities and Exchange Commission’s~~SEC’s rules and forms and such information is accumulated and communicated to ~~our~~ management, including ~~our~~the principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding disclosure.

There has been no change in ~~our~~the Registrants’ internal controls over financial reporting that occurred during the three months ended December 31, ~~2015~~2018 that has materially affected, or is reasonably likely to materially affect, ~~our~~the Registrants’ internal controls over financial reporting.

Management’s Annual Report on Internal Control over Financial Reporting

~~Our~~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 ~~our~~the Registrants’ management, including ~~our~~their respective principal executive ~~officer~~officers and principal financial ~~officer, we~~officers, the Registrants conducted an evaluation of the effectiveness of ~~our~~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 ~~our~~the Registrants’ evaluation under the framework in Internal Control — Integrated Framework (2013), ~~our~~the Registrants’ management has concluded, in each case, that ~~our~~their internal control over financial reporting was effective as of December 31, ~~2015~~2018.

Deloitte & Touche LLP, ~~the Company’s~~CenterPoint Energy’s independent registered public accounting firm, has issued an attestation report on the effectiveness of ~~our~~CenterPoint Energy’s internal control over financial reporting as of December 31, ~~2015~~2018 which is set forth below. This report is not applicable to Houston Electric or CERC as they are not accelerated or large accelerated filers.

~~122~~

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, ~~2015~~,2018, based on criteria established in Internal Control —- Integrated Framework (2013) ~~(2013)~~ issued by the Committee of Sponsoring Organizations of the Treadway ~~Commission.~~ Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018, 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, 2018, of the Company and our report dated February 28, 2019, 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~~over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the ~~Public Company Accounting Oversight Board (United States).~~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 by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, 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. 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 ~~the~~its inherent limitations, of internal control over financial reporting ~~including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud~~ may not ~~be prevented~~prevent or ~~detected on a timely basis.~~detect misstatements. Also, projections of any evaluation of ~~the~~ effectiveness ~~of the internal control over financial reporting~~ to future periods are subject to the risk that ~~the~~ controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

~~In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of~~ ~~December 31, 2015, based on the criteria established in~~ ~~Internal Control — Integrated Framework~~ ~~(2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.~~

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedules as of and for the year ended December 31, 2015 of the Company and our report dated ~~February 26, 2016expressed an unqualified opinion on those financial statements.~~

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

February ~~26, 2016~~28, 2019

~~123~~


Item 9B.	Other Information

~~Amendment to Bylaws~~Amended and Restated Short Term Incentive Plan

Effective ~~February 25, 2016,~~January 1, 2019, the Board of Directors of CenterPoint Energy ~~Inc. (the Board)~~ amended and restated ~~its bylaws (the Bylaws).~~the CenterPoint Energy, Inc. Short Term Incentive Plan. The ~~Bylaws include,~~Short Term Incentive Plan, as amended and restated, includes, among other things, the following changes:

•~~Provide~~Revised eligibility requirements to provide clarity with respect to participants employed for a portion of the ~~Board with explicit authority to cancel, postpone or reschedule a shareholder meeting.~~applicable plan year;

•~~Provide~~Amended methodology for calculating payments upon retirement;

Removed manager discretion with respect to terminations after the ~~chairman~~plan year but before the payment date to conform to operational practice; and

Deleted provisions related to Section 162(m) of the ~~meeting with explicit authority~~Internal Revenue Code to ~~adjourn or recess a shareholder meeting.~~

•~~Allow shareholder meetings to proceed by means of remote communication.~~

•~~Clarify the powers of the chairman of the meeting to conduct a shareholder meeting.~~

•~~Provide for additional disclosure requirements for notices of director nominations and shareholder proposals.~~

•~~Provide an explicit confidentiality obligation for directors.~~reflect current legislative changes.

The foregoing description of the ~~terms of the Bylaws~~Short Term Incentive Plan does not purport to be complete and is subject to, and qualified in its entirety by, reference to the complete text of the ~~Bylaws,~~Short Term Incentive Plan, a copy of which is filed as Exhibit ~~3(b)~~10(m) to this Annual Report on Form 10-K and incorporated by reference herein.

~~Amendments to Forms~~Termination of ~~Award Agreements under Long Term Incentive Plan~~Certain Plans of Vectren

On February ~~25, 2016, the Compensation Committee of~~26, 2019, the Board ~~approved revisions to~~of Directors of Vectren terminated (i) the ~~forms of award agreements~~At Risk Compensation Plan, dated May 1, 2001, as most recently amended and restated May 24, 2016, (ii) the Vectren Incentive Plan Guidelines and (iii) the Severance Plan for ~~qualified performance awards~~Executive Officers, dated December 31, 2011, as most recently amended and restricted stock unit awards with service-based vesting under CenterPoint Energy’s long-term incentive plan. The revised forms provide for pro rata vesting upon retirement for a “retirement eligible” participant (age 55 or greater with at least five years of service) and removerestated February 21, 2017, the requirement that such a participant be employed for at least the first six months of the calendar year in which the award is granted to qualify for such pro rata vesting. The revised form of award agreement for executive chairman restricted stock unit awards with service-based vesting also provides for pro rata vesting upon termination without cause and removes the requirement that the executive chairman be employed for at least the first six months of the calendar year in which the award is granted to qualify for such pro rata vesting.

The foregoing description of the forms of award agreements does not purport to be complete and is subject to, and qualified in its entirety by, reference to the complete text of the following forms of agreements for qualified performance awards, qualified performance awards for the executive chairman, restricted stock unit awards with service-based vesting and executive chairman restricted stock unit awards with service-based vesting, copiesterminations of which are ~~filed~~effective as ~~Exhibits 10(ll)(2), 10(ll)(3), 10(ll)(5)~~of February 26, 2019. With respect to the At Risk Compensation Plan and ~~10(ll)(7), respectively,~~the Vectren Incentive Plan Guidelines, there were no awards outstanding under each respective plan as of the termination. With respect to ~~this Annual Report on Form 10-K and are incorporated by reference herein.~~the Severance Plan for Executive Officers, there were no participants under such plan upon the closing of the Merger.

PART III


Item 10.	Directors, Executive Officers and Corporate Governance

~~The~~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 ~~2016~~2019 annual meeting of shareholders pursuant to SEC Regulation 14A. Such definitive proxy statement relates to a meeting of shareholders involving the election of directors and the portions thereof called for by Item 10 are incorporated herein by reference pursuant to Instruction G to Form 10-K.

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

~~The~~For CenterPoint Energy, the information called for by Item 11 will be set forth in the definitive proxy statement relating to CenterPoint Energy’s ~~2016~~2019 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.

~~124~~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

~~The~~For CenterPoint Energy, the information called for by Item 12 will be set forth in the definitive proxy statement relating to CenterPoint Energy’s ~~2016~~2019 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

~~The~~For CenterPoint Energy, the information called for by Item 13 will be set forth in the definitive proxy statement relating to CenterPoint Energy’s ~~2016~~2019 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

~~The~~For CenterPoint Energy, the information called for by Item 14 will be set forth in the definitive proxy statement relating to CenterPoint Energy’s ~~2016~~2019 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, 2018 and 2017 by their principal accounting firm, Deloitte & Touche LLP, are set forth below.



	Year Ended December 31,
	2018				2017
	Houston Electric		CERC		Houston Electric		CERC
Audit fees (1)	$	859,950	$	1,360,800	$	819,364	$	1,296,576
Audit-related fees (2)	529,000		121,000		516,000		106,000
Total audit and audit-related fees	1,388,950		1,481,800		1,335,364		1,402,576
Tax fees	—		—		—		—
All other fees	—		—		—		—
Total fees	$	1,388,950	$	1,481,800	$	1,335,364	$	1,402,576


(1)	For 2018 and 2017, 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 2018 and 2017, 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	7584
Statements of Consolidated Income for the Three Years Ended December 31, ~~2015~~2018	7685
Statements of Consolidated Comprehensive Income for the Three Years Ended December 31, ~~2015~~2018	7786
Consolidated Balance Sheets as of December 31, ~~2015~~2018 and ~~2014~~2017	7887
Statements of Consolidated Cash Flows for the Three Years Ended December 31, ~~2015~~2018	7989
Statements of Consolidated ~~Shareholders’~~Changes in Equity for the Three Years Ended December 31, ~~2015~~2018	8190
Houston Electric
Report of Independent Registered Public Accounting Firm	91
Statements of Consolidated Income for the Three Years Ended December 31, 2018	92
Statements of Consolidated Comprehensive Income for the Three Years Ended December 31, 2018	93
Consolidated Balance Sheets as of December 31, 2018 and 2017	94
Statements of Consolidated Cash Flows for the Three Years Ended December 31, 2018	95
Statements of Consolidated Changes in Equity for the Three Years Ended December 31, 2018	95
CERC
Report of Independent Registered Public Accounting Firm	97
Statements of Consolidated Income for the Three Years Ended December 31, 2018	98
Statements of Consolidated Comprehensive Income for the Three Years Ended December 31, 2018	99
Consolidated Balance Sheets as of December 31, 2018 and 2017	100
Statements of Consolidated Cash Flows for the Three Years Ended December 31, 2018	102
Statements of Consolidated Changes in Equity for the Three Years Ended December 31, 2018	103
Combined Notes to Consolidated Financial Statements	82104

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 ~~99.3.~~99.1.

(a)(2) Financial Statement Schedules for the Three Years Ended December 31, ~~2015~~



~~Report of Independent Registered Public Accounting Firm~~	~~126~~
~~I — Condensed Financial Information of CenterPoint Energy, Inc. (Parent Company)~~	~~127~~
~~II — Valuation and Qualifying Accounts~~	~~133~~

2018.

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 ~~135,~~170, 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.

~~125~~

~~REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM~~

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

~~CenterPoint Energy, Inc.~~

~~Houston, Texas~~

~~We have audited the consolidated financial statements of CenterPoint Energy, Inc. and subsidiaries (the “Company”) as of~~ Item 16.~~December 31, 2015~~ ~~and~~ ~~2014, and for each of the three years in the period ended~~ ~~December 31, 2015, and the Company’s internal control over financial reporting as of~~ ~~December 31, 2015, and have issued our reports thereon dated~~ ~~February 26, 2016; such reports are included elsewhere in this~~ Form 10-K. Our audits also included the financial statement schedules of the Company listed in the index at Item 15 (a)(2). These financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion based on our audits. In our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.10-K Summary

~~/s/ DELOITTE & TOUCHE LLP~~None.

~~Houston, Texas~~

~~February 26, 2016~~

~~126~~

~~CENTERPOINT ENERGY, INC.~~

~~SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF~~

CENTERPOINT ENERGY, INC. ~~(PARENT COMPANY)~~AND SUBSIDIARIES

CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC AND SUBSIDIARIES

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

~~STATEMENTS~~EXHIBITS TO THE COMBINED ANNUAL REPORT ON FORM 10-K

For Fiscal Year Ended December 31, 2018

INDEX OF ~~INCOME~~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

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

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(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)

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(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

3(a)

—

Restated Articles of Incorporation of CenterPoint Energy

CenterPoint Energy’s Form 8-K dated July 24, 2008

1-31447

3.2

For the Year Ended December 31,
2015 2014 2013
(in millions)
Expenses:
Operation and Maintenance Expenses $ (12 ) $ (22 ) $ (13 )
Total (12 ) (22 ) (13 )
Other Income (Expense):
Interest Income from Subsidiaries 2
—
8
Other Expense (1 ) (1 ) (5 )
Gain (Loss) on Indexed Debt Securities 74
(86 ) (193 )
Interest Expense to Subsidiaries —
—
(24 )
Interest Expense (99 ) (103 ) (104 )
Total (24 ) (190 ) (318 )
Loss Before Income Taxes, Equity in Subsidiaries (36 ) (212 ) (331 )
Income Tax Benefit 28
115
137
Loss Before Equity in Subsidiaries (8 ) (97 ) (194 )
Equity Income (Loss) of Subsidiaries (684 ) 708
505
Net Income (Loss) $ (692 ) $ 611
$ 311

Exhibit

Number

Description

Report or Registration Statement

SEC File or

Registration

Number

Exhibit

Reference

CenterPoint Energy

Houston Electric

CERC

3(b)

Articles of Conversion of Reliant Energy Incorporated

Houston Electric’s Form 8-K dated August 31, 2002

1-3187

3(a)

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

3(d)

—

Certificate of Incorporation of RERC Corp.

CERC Form 10-K for the year ended December 31, 1997

1-13265

3(a)(1)

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)

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)

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)

3(h)

—

Third Amended and Restated Bylaws of CenterPoint Energy

CenterPoint Energy’s Form 8-K dated February 21, 2017

1-31447

3.1

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

3(j)

—

Bylaws of RERC Corp.

CERC Form 10-K for the year ended December 31, 1997

1-13265

3(b)

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)

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

~~See Notes to Condensed Financial Information (Parent Company) and~~

~~CenterPoint Energy, Inc. and Subsidiaries Notes to Consolidated Financial Statements in Part II, Item 8~~

~~127~~

~~CENTERPOINT ENERGY, INC.~~

~~SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF~~

~~CENTERPOINT ENERGY, INC. (PARENT COMPANY)~~

~~STATEMENTS OF COMPREHENSIVE INCOME~~

Year Ended December 31,
2015 2014 2013
(in millions)
Net income (loss) $ (692 ) $ 611
$ 311
Other comprehensive income:

Adjustment to pension and other postretirement plans (net of tax of $12, $5 and $25) 20
3
44
Reclassification of deferred loss from cash flow hedges realized in net income (net of tax) —
1
1
Other comprehensive income 20
4
45
Comprehensive income (loss) $ (672 ) $ 615
$ 356

Exhibit

Number

Description

Report or Registration Statement

SEC File or

Registration

Number

Exhibit

Reference

CenterPoint Energy

Houston Electric

CERC

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

4(a)

—

Form of CenterPoint Energy Stock Certificate

CenterPoint Energy’s Registration Statement on Form S-4

333-69502

4.1

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

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

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

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

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

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)

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)

~~See Notes to Condensed Financial Information (Parent Company) and~~

~~CenterPoint Energy, Inc. and Subsidiaries Notes to Consolidated Financial Statements in Part II, Item 8~~

~~128~~

~~CENTERPOINT ENERGY, INC.~~

~~SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF~~

~~CENTERPOINT ENERGY, INC. (PARENT COMPANY)~~

~~BALANCE SHEETS~~

December 31,
2015 2014
(in millions)
ASSETS
Current Assets:
Cash and cash equivalents $ —
$ —
Notes receivable — subsidiaries 352
227
Accounts receivable — subsidiaries 85
230
Other assets 135
87
Total current assets 572
544
Other Assets:

Investment in subsidiaries 5,565
6,529
Other assets 831
811
Total other assets 6,396
7,340
Total Assets $ 6,968
$ 7,884
LIABILITIES AND SHAREHOLDERS’ EQUITY

Current Liabilities:

Notes payable — subsidiaries $ 59
$ 142
Indexed debt 154
152
Current portion of other long-term debt —
269
Indexed debt securities derivative 442
541
Accounts payable:

Subsidiaries 39
80
Other 4
2
Interest accrued 11
13
Other —
22
Total current liabilities 709
1,221
Other Liabilities:

Deferred tax liabilities 908
815
Benefit obligations 505
441
Other 1
1
Total non-current liabilities 1,414
1,257
Long-Term Debt 1,384
858
Shareholders’ Equity:

Common stock 4
4
Additional paid-in capital 4,180
4,169
Retained earnings (accumulated deficit) (657 ) 461
Accumulated other comprehensive loss (66 ) (86 )
Total shareholders’ equity 3,461
4,548
Total Liabilities and Shareholders’ Equity $ 6,968
$ 7,884

Exhibit

Number

Description

Report or Registration Statement

SEC File or

Registration

Number

Exhibit

Reference

CenterPoint Energy

Houston Electric

CERC

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)

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(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(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(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(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)

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)

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)

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)

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)

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)

~~See Notes to Condensed Financial Information (Parent Company) and~~

~~CenterPoint Energy, Inc. and Subsidiaries Notes to Consolidated Financial Statements in Part II, Item 8~~

~~129~~

~~CENTERPOINT ENERGY, INC.~~

~~SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF~~

~~CENTERPOINT ENERGY, INC. (PARENT COMPANY)~~

~~STATEMENTS OF CASH FLOWS~~

For the Year Ended December 31,
2015 2014 2013
(in millions)
Operating Activities:
Net income (loss) $ (692 ) $ 611
$ 311
Non-cash items included in net income (loss):

Equity (income) loss of subsidiaries 684
(708 ) (505 )
Deferred income tax expense 152
86
6
Amortization of debt issuance costs 3
4
4
(Gain) loss on indexed debt securities (74 ) 86
193
Changes in working capital:

Accounts receivable/(payable) from subsidiaries, net 164
(7 ) 47
Accounts payable 2
(3 ) 5
Other current assets (3 ) —
—
Other current liabilities (45 ) (83 ) 42
Common stock dividends received from subsidiaries 295
315
766
Other (76 ) (76 ) (70 )
Net cash provided by operating activities 410
225
799
Investing Activities:

Decrease (increase) in notes receivable from subsidiaries (125 ) (139 ) 868
Net cash provided by (used in) investing activities (125 ) (139 ) 868
Financing Activities:

Proceeds from commercial paper, net 525
191
—
Payments on long-term debt (269 ) —
(151 )
Debt issuance costs —
(1 ) (2 )
Common stock dividends paid (426 ) (408 ) (355 )
Proceeds from issuance of common stock, net —
1
4
Increase (decrease) in notes payable to subsidiaries (83 ) 131
(1,173 )
Redemption of indexed debt securities —
—
(8 )
Distribution to ZENS holders (32 ) —
—
Other —
—
18
Net cash used in financing activities (285 ) (86 ) (1,667 )
Net Decrease in Cash and Cash Equivalents —
—
—
Cash and Cash Equivalents at Beginning of Year —
—
—
Cash and Cash Equivalents at End of Year $ —
$ —
$ —

~~See Notes to Condensed Financial Information (Parent Company) and~~

~~CenterPoint Energy, Inc. and Subsidiaries Notes to Consolidated Financial Statements in Part II, Item 8~~

~~130~~

~~CENTERPOINT ENERGY, INC.~~

~~SCHEDULE I — NOTES TO CONDENSED FINANCIAL INFORMATION (PARENT COMPANY)~~

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)

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

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

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

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

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

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)

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)

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

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

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

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

~~(1)~~ ~~Background.~~ The condensed parent company financial statements and notes of CenterPoint Energy, Inc. (CenterPoint Energy) should be read in conjunction with the consolidated financial statements and notes of CenterPoint Energy, Inc. and subsidiaries appearing in the Annual Report on Form 10-K. Credit facilities at CenterPoint Energy Houston Electric, LLC (CenterPoint Houston) and CenterPoint Energy Resources Corp., indirect wholly-owned subsidiaries of CenterPoint Energy, limit debt, excluding transition and system restoration bonds, as a percentage of their consolidated capitalization to ~~65%. These covenants could restrict the ability of these subsidiaries to distribute dividends to CenterPoint Energy.~~

~~(2)~~ ~~New Accounting Pronouncements.~~ In ~~February 2015, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update No. 2015-02,~~ ~~Consolidation (Topic 810): Amendments to the Consolidation~~ ~~Analysis~~ ~~(ASU 2015-02). ASU 2015-02 changes the analysis that reporting organizations must perform to evaluate whether they should consolidate certain legal entities, such as limited partnerships.~~ The changes include, among others, modification of the evaluation of whether limited partnerships and similar legal entities are variable interest entities (VIEs) or voting interest entities and elimination of the presumption that a general partner should consolidate a limited partnership. ASU 2015-02 does not amend the related party guidance for situations in which power is shared between two or more entities that hold interests in a VIE. ASU 2015~~-02 is effective for~~ ~~fiscal years, and interim periods within those years,~~ ~~beginning after December 15, 2015.~~ ~~CenterPoint Energy does not believe that ASU 2015-02 will have a material impact on its financial position, results of operations, cash flows and disclosures.~~

~~In April 2015, the FASB issued Accounting Standards Update No. 2015-03,~~ ~~Interest-Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Cost~~ ~~(ASU 2015-03)~~. ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by ASU 2015-03. CenterPoint Energy will adopt ASU 2015-03 retrospectively on January 1, 2016, which will result in a reduction of both other long-term assets and long-term debt on its Consolidated Balance Sheets. CenterPoint Energy had debt issuance costs of $15 million and $18 million included in other long-term assets on its Consolidated Balance Sheets as of December 31, 2015 and 2014, respectively.

~~In April 2015, the FASB issued Accounting Standards Update No. 2015-05,~~ ~~Intangibles-Goodwill and Other-Internal-Use Software~~ (~~Subtopic 350-40~~) (ASU 2015-05). ASU 2015-05 provides guidance to customers about whether a cloud computing arrangement includes a software license. If a cloud computing arrangement includes a software license, the customer should account for the software license element of the arrangement consistent with the acquisition of other software licenses. If a cloud computing arrangement does not include a software license, the customer should account for the arrangement as a service contract. The guidance will not change a customer’s accounting for service contracts. ASU 2015-05 is effective for fiscal years, and interim periods within the fiscal years, beginning after December 15, 2015 and may be adopted either prospectively or retrospectively. CenterPoint Energy will adopt ASU 2015-05 prospectively on January 1, 2016. CenterPoint Energy does not believe that ASU 2015-05 will have a material impact on its financial position, results of operations, cash flows and disclosures.

~~In May 2014, the FASB issued Accounting Standards Update No. 2014-09,~~ ~~Revenue from Contracts with Customers (Topic 606)~~ (ASU 2014-09), which supersedes most current revenue recognition guidance. ASU 2014-09 provides a comprehensive new revenue recognition model that requires revenue to be recognized in a manner that depicts the transfer of goods or services to a customer at an amount that reflects the consideration expected to be received in exchange for those goods or services. ASU 2014-09 was initially effective for fiscal years, and interim periods within those years, beginning after December 15, 2016. Early adoption is not permitted, and entities have the option of using either a full retrospective or a modified retrospective adoption approach. In August 2015, the FASB issued Accounting Standard Update No. 2015-14, ~~Revenue from Contracts with Customers (Topic 606):Deferral of the Effective Date~~, which delays the effective date of ASU 2014-09 by one year. CenterPoint Energy is currently evaluating the impact that ASU 2014-09 will have on its financial position, results of operations, cash flows and disclosures, and will adopt ASU 2014-09 on January 1, 2018 as permitted by the new guidance.

~~In July 2015,~~ ~~the FASB issued Accounting Standards Update No. 2015-11,~~ ~~Inventory (Topic 330) Simplifying the Measurement of Inventory~~ (ASU 2015-11). ASU 2015-11 changes the subsequent measurement guidance for inventory accounted for using methods other than the last in, first out (LIFO) and Retail Inventory methods. Companies will subsequently measure inventory at the lower of cost and net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. Subsequent measurement is unchanged for inventory measured using LIFO or the retail inventory method. ASU 2015-11 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, with early adoption permitted. CenterPoint Energy does not believe that ASU 2015-11 will have a material impact on its financial position, results of operations, cash flows and disclosures.

~~131~~

~~In November 2015, the FASB issued Accounting Standards Update No. 2015-17,~~ ~~Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes~~ (ASU 2015-17). ASU 2015-17 requires deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position. CenterPoint Energy adopted ASU 2015-17 retrospectively starting with fiscal year 2015. As such, certain prior period amounts have been classified to conform to the current presentation. In the Consolidated Balance Sheet as of December 31, 2014, CenterPoint Energy reclassified $575 million from current deferred income tax liabilities to increase deferred income taxes within non-current liabilities.

Management believes that other recently issued standards, which are not yet effective, will not have a material impact on CenterPoint Energy’s consolidated financial position, results of operations or cash flows upon adoption.

~~(3)~~ ~~Long-term Debt.~~ In June 2015, CenterPoint Energy repaid its $200 million 6.85% Senior Notes using proceeds from its commercial paper program. In October 2015, CenterPoint Energy repaid its $69 million 4.9% pollution control bonds using proceeds from its commercial paper program. CenterPoint Energy’s $1.2 billion revolving credit facility backstops its $1.0 billion commercial paper program.

~~Retirement of Bonds.~~ ~~In November 2015, CenterPoint Energy retired $740 million of tax-exempt municipal bonds that had been held for remarketing.~~

~~Credit Facilities.~~ ~~As of December 31, 2015 and 2014, CenterPoint Energy had the following revolving credit facility and utilization of such facility:~~

December 31, 2015 December 31, 2014
Size of
Facility Loans Letters
of Credit Commercial
Paper Loans Letters
of Credit Commercial
Paper
(in millions)
CenterPoint Energy $ 1,200
$ —
$ 6
$ 716
(1) $ —
$ 6
$ 191
(1)

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

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

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)

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)

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

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

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

†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

4(i)(1)

~~Weighted average interest rate was 0.79%~~—

Indenture, dated as of February 1, 1998, between Reliant Energy Resources Corp. (RERC Corp.) and ~~0.63%~~Chase Bank of Texas, National Association, as Trustee

CERC Corp.’s Form 8-K dated February 5, 1998

1-13265

4.1

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)

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

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)

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)

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

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

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

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

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

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

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

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)

Exhibit

Number

Description

Report or Registration Statement

SEC File or

Registration

Number

Exhibit

Reference

CenterPoint Energy

Houston Electric

CERC

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, ~~2015~~2005

1-31447

4(h)(4)

4(l)(1)

—

$1,600,000,000 Credit Agreement dated as of March 3, 2016, among CenterPoint Energy, as Borrower, and ~~2014, respectively.~~the banks named therein

CenterPoint Energy’s Form 8-K dated March 3, 2016

1-31447

4.1

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

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

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

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

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

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

CenterPoint Energy’s $1.2 billion revolving credit facility, which is scheduled to terminate on September 9, 2019, can be drawn at the London Interbank Offered Rate (LIBOR) plus 1.25% based on CenterPoint Energy’s current credit ratings. The revolving credit facility contains a financial covenant which limits CenterPoint Energy’s consolidated debt (excluding transition and system restoration bonds) to an amount not to exceed 65% of CenterPoint Energy’s consolidated capitalization. At December 31, 2015, CenterPoint Energy’s debt (excluding transition and system restoration bonds) to capital ratio, as defined in its credit facility agreement, was 55.1%. The financial covenant limit will temporarily increase from 65% to 70% if CenterPoint Houston experiences damage from a natural disaster in its service territory and CenterPoint Energy certifies to the administrative agent that CenterPoint Houston has incurred system restoration costs reasonably likely to exceed $100 million in a consecutive twelve-month period, all or part of which CenterPoint Houston 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.

~~CenterPoint Energy’s maturities~~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 ~~excluding~~instruments, including indentures, under which the ~~indexed debt~~total amount of securities ~~obligation, are $250 million in 2017, $350 million in 2018~~authorized does not exceed 10% of the total assets of the Registrants and ~~$716 million in 2019. There are no maturities~~its subsidiaries on a consolidated basis. The Registrants hereby agree to furnish a copy of ~~long-term debt in either 2016 or 2020.~~

~~(4)~~ ~~Guarantees.~~ ~~CenterPoint Energy has provided guarantees (CenterPoint Midstream Guarantees) with respect~~any such instrument to the performance of certain obligations of Enable under long-term gas gathering and treating agreements with an indirect, wholly-owned subsidiary of Encana Corporation (Encana) and an indirect, wholly-owned subsidiary of Royal Dutch Shell plc (Shell). Under the terms of the omnibus agreement entered into in connection with the closing of the formation of Enable, Enable and CenterPoint Energy have agreed to use commercially reasonable efforts and cooperate with each other to terminate the CenterPoint Midstream Guarantees and to release CenterPoint Energy from such guarantees by causing Enable or one of its subsidiaries to enter into substitute guarantees or to assume the CenterPoint Midstream Guarantees as applicable. The guarantee in favor of the indirect, wholly-owned subsidiary of Encana was released on August 24, 2015. As of December 31, 2015, CenterPoint Energy had guaranteed Enable’s obligations up to an aggregate amount of $50 million under the guarantee in favor of the indirect, wholly-owned subsidiary of Shell.

~~132~~

~~CENTERPOINT ENERGY, INC.~~

~~SCHEDULE II —VALUATION AND QUALIFYING ACCOUNTS~~

~~For the Three Years Ended~~ ~~December 31, 2015~~SEC upon request.

Column A Column B Column C Column D Column E
Additions

Balance at
Beginning
of Period

Charged
to Income

Charged to
Other
Accounts

Deductions
From
Reserves (1)

Balance at
End of
Period
Description (in millions)
Year Ended December 31, 2015
Accumulated provisions:
Uncollectible accounts receivable $ 26
$ 19
$ (2 ) $ 23
$ 20
Deferred tax asset valuation allowance 2
—
—
—
2
Year Ended December 31, 2014
Accumulated provisions:
Uncollectible accounts receivable $ 28
$ 22
$ 2
$ 26
$ 26
Deferred tax asset valuation allowance 2
—
—
—
2
Year Ended December 31, 2013
Accumulated provisions:
Uncollectible accounts receivable $ 25
$ 21
$ 1
$ 19
$ 28
Deferred tax asset valuation allowance 2
—
—
—
2

~~(1)~~

Exhibit

Number

~~Deductions from reserves represent losses~~

Description

Report or ~~expenses~~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 ~~which~~ the ~~respective reserves were created. In the case of the uncollectible accounts reserve, such deductions are net of recoveries of amounts previously written off.~~quarter ended March 31, 2011

1-31447

10.3

~~133~~

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

*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

*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

*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

*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

*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

*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

*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

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

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)

†10(h)

—

Summary of Certain Compensation Arrangements of the Executive Chairman of the Board

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

Exhibit

Number

Description

Report or Registration Statement

SEC File or

Registration

Number

Exhibit

Reference

CenterPoint Energy

Houston Electric

CERC

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)

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

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

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

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)

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)

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)

*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

*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

*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

*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

†*10(m)

—

CenterPoint Energy Short Term Incentive Plan, as amended and restated effective January 1, 2019

Exhibit

Number

Description

Report or Registration Statement

SEC File or

Registration

Number

Exhibit

Reference

CenterPoint Energy

Houston Electric

CERC

*10(n)

—

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

10(o)

—

City of Houston Franchise Ordinance

CenterPoint Energy’s Form 10-Q for the quarter ended June 30, 2005

1-31447

10.1

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

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

*10(q)(1)

—

CenterPoint Energy, Inc. 2009 Long Term Incentive Plan

CenterPoint Energy’s Schedule 14A dated March 13, 2009

1-31447

*10(q)(2)

—

Form of Performance Award Agreement for 20XX - 20XX Performance Cycle under Exhibit 10(q)(1)

CenterPoint Energy’s Form 10-Q for the quarter ended March 31, 2018

1-31447

10.3

*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

*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

*10(q)(5)

—

Form of 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

10.5

*10(q)(6)

—

Form of Restricted Stock Unit Award Agreement (Retention, Service-Based Vesting) under Exhibit 10(q)(1)

CenterPoint Energy’s Form 10-Q for the quarter ended March 31, 2018

1-31447

10.6

*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

†10(r)

—

Summary of Non-Employee Director Compensation

†10(s)

—

Summary of Senior Executive Officer Compensation

Exhibit

Number

Description

Report or Registration Statement

SEC File or

Registration

Number

Exhibit

Reference

CenterPoint Energy

Houston Electric

CERC

10(t)

—

Change in Control Plan

CenterPoint Energy’s Form 8-K dated April 27, 2017

1-31447

10.1

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)

10(v)

—

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

10(w)

—

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

10(x)

—

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

10(y)

—

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

10(z)

—

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

10(aa)

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

10(bb)

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

10(cc)

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

Exhibit

Number

Description

Report or Registration Statement

SEC File or

Registration

Number

Exhibit

Reference

CenterPoint Energy

Houston Electric

CERC

10(dd)

—

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

10(ee)

—

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

10(ff)

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

†21

—

Subsidiaries of CenterPoint Energy

†23.1.1

—

Consent of Deloitte & Touche LLP

†23.1.2

—

Consent of Deloitte & Touche LLP

†23.1.3

—

Consent of Deloitte & Touche LLP

†23.2

—

Consent of Deloitte & Touche LLP, Independent Registered Public Accounting Firm of Enable Midstream Partners, LP

†31.1.1

—

Rule 13a-14(a)/15d-14(a) Certification of Scott M. Prochazka

†31.1.2

—

Rule 13a-14(a)/15d-14(a) Certification of Scott M. Prochazka

†31.1.3

—

Rule 13a-14(a)/15d-14(a) Certification of Scott M. Prochazka

†31.2.1

—

Rule 13a-14(a)/15d-14(a) Certification of William D. Rogers

†31.2.2

—

Rule 13a-14(a)/15d-14(a) Certification of William D. Rogers

†31.2.3

—

Rule 13a-14(a)/15d-14(a) Certification of William D. Rogers

†32.1.1

—

Section 1350 Certification of Scott M. Prochazka

†32.1.2

—

Section 1350 Certification of Scott M. Prochazka

†32.1.3

—

Section 1350 Certification of Scott M. Prochazka

†32.2.1

—

Section 1350 Certification of William D. Rogers

†32.2.2

—

Section 1350 Certification of William D. Rogers

†32.2.3

—

Section 1350 Certification of William D. Rogers

Exhibit

Number

Description

Report or Registration Statement

SEC File or

Registration

Number

Exhibit

Reference

CenterPoint Energy

Houston Electric

CERC

99.1

—

Financial Statements of Enable Midstream Partners, LP as of December 31, 2018 and 2017 and for the years ended December 31, 2018, 2017and 2016

Part II, Item 8 of Enable Midstream Partners, LP’s Form 10-K for the year ended December 31, 2018

001-36413

Item 8

†101.INS

—

XBRL Instance Document

†101.SCH

—

XBRL Taxonomy Extension Schema Document

†101.CAL

—

XBRL Taxonomy Extension Calculation Linkbase Document

†101.DEF

—

XBRL Taxonomy Extension Definition Linkbase Document

†101.LAB

—

XBRL Taxonomy Extension Labels Linkbase Document

†101.PRE

—

XBRL Taxonomy Extension Presentation Linkbase Document

**Schedules to this agreement have been omitted pursuant to Item 601(b)(2) of Regulation S-K. A copy of any omitted schedules will be furnished supplementally to the SEC upon request; provided, however, that the parties may request confidential treatment pursuant to Rule 24b-2 of the Exchange Act for any document so furnished.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the ~~registrant has~~Registrants have duly caused this report to be signed on ~~its~~their behalf by the undersigned, thereunto duly authorized, in the City of Houston, the State of Texas, on the ~~26th~~28th day of February, ~~2016~~.2019.



	CENTERPOINT ENERGY, INC.
	(Registrant)


	By: /s/ Scott M. Prochazka
	Scott M. Prochazka
	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 ~~26, 2016~~28, 2019.



Signature		Title
/s/ SCOTT M. PROCHAZKA		President, Chief Executive Officer and
Scott M. Prochazka		Director (Principal Executive Officer and Director)

/s/ WILLIAM D. ROGERS		Executive Vice President and Chief
William D. Rogers		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/ ~~MICHAEL P. JOHNSON~~LESLIE D. BIDDLE		Director
~~Michael P. Johnson~~

~~/s/ JANIECE M. LONGORIA~~		~~Director~~
~~Janiece M. Longoria~~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/ JOHN W. SOMERHALDER II		Director
John W. Somerhalder II

/s/ PETER S. WAREING		Director
Peter S. Wareing

~~134~~

~~CENTERPOINT ENERGY, INC.~~

~~EXHIBITS TO THE ANNUAL REPORT ON FORM 10-K~~

~~For Fiscal Year Ended~~ ~~December 31, 2015~~



	CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC
	(Registrant)

By:	/s/ SCOTT M. PROCHAZKA
	Scott M. Prochazka
	Manager

~~INDEX OF EXHIBITS~~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 28, 2019.

Exhibits included with this report are designated by a cross (†); all exhibits not so designated are incorporated herein by reference to a prior filing as indicated. Exhibits designated by an asterisk (*) are management contracts or compensatory plans or arrangements required to be filed as exhibits to this Form 10-K by Item 601(b)(10)(iii) of Regulation S-K. CenterPoint Energy has not filed the exhibits and schedules to Exhibit 2. CenterPoint Energy hereby agrees to furnish supplementally a copy of any schedule omitted from Exhibit 2 to the SEC upon request.

Exhibit
Number
Description Report or Registration Statement
SEC File or
Registration
Number

Exhibit
Reference
2 — Transaction Agreement dated July 21, 2004 among CenterPoint Energy, Utility Holding, LLC, NN Houston Sub, Inc., Texas Genco Holdings, Inc. (Texas Genco), HPC Merger Sub, Inc. and GC Power Acquisition LLC CenterPoint Energy’s Form 8-K dated July 21, 2004 1-31447 10.1
3(a) — Restated Articles of Incorporation of CenterPoint Energy CenterPoint Energy’s Form 8-K dated July 24, 2008 1-31447 3.2
†3(b)
— Second Amended and Restated Bylaws of CenterPoint Energy
3(c) —
Statement of Resolutions Deleting Shares Designated Series A Preferred Stock of CenterPoint Energy

CenterPoint Energy’s Form 10-K for the year ended December 31, 2011 1-31447 3(c)
4(a) — Form of CenterPoint Energy Stock Certificate CenterPoint Energy’s Registration Statement on Form S-4 333-69502 4.1
4(c) — Contribution and Registration Agreement dated December 18, 2001 among Reliant Energy, CenterPoint Energy and the Northern Trust Company, trustee under the Reliant Energy, Incorporated Master Retirement Trust CenterPoint Energy’s Form 10-K for the year ended December 31, 2001 1-31447 4.3
4(d)(1) — Mortgage and Deed of Trust, dated November 1, 1944 between Houston Lighting and Power Company (HL&P) and Chase Bank of Texas, National Association (formerly, South Texas Commercial National Bank of Houston), as Trustee, as amended and supplemented by 20 Supplemental Indentures thereto HL&P’s Form S-7 filed on August 25, 1977 2-59748 2(b)
4(d)(2) — Twenty-First through Fiftieth Supplemental Indentures to Exhibit 4(d)(1) HL&P’s Form 10-K for the year ended December 31, 1989 1-3187 4(a)(2)
4(d)(3) — Fifty-First Supplemental Indenture to Exhibit 4(d)(1) dated as of March 25, 1991 HL&P’s Form 10-Q for the quarter ended June 30, 1991 1-3187 4(a)
4(d)(4) — Fifty-Second through Fifty-Fifth Supplemental Indentures to Exhibit 4(d)(1) each dated as of March 1, 1992 HL&P’s Form 10-Q for the quarter ended March 31, 1992 1-3187 4
4(d)(5) — Fifty-Sixth and Fifty-Seventh Supplemental Indentures to Exhibit 4(d)(1) each dated as of October 1, 1992 HL&P’s Form 10-Q for the quarter ended September 30, 1992 1-3187 4

~~135~~



Signature		Title

/s/ SCOTT M. PROCHAZKA		Manager and Chairman
(Scott M. Prochazka)		(Principal Executive Officer)

/s/ WILLIAM D. ROGERS		Executive Vice President and Chief Financial Officer
(William D. Rogers)		(Principal Financial Officer)

/s/ KRISTIE L. COLVIN		Senior Vice President and Chief Accounting Officer
(Kristie L. Colvin)		(Principal Accounting Officer)



~~4(d)(6)~~	—CENTERPOINT ENERGY RESOURCES CORP.
	~~Fifty-Eighth and Fifty-Ninth Supplemental Indentures to Exhibit 4(d)(1) each dated as of March 1, 1993~~(Registrant)

~~HL&P’s Form 10-Q for the quarter ended March 31, 1993~~By:	/s/ SCOTT M. PROCHAZKA
	~~1-3187~~Scott M. Prochazka
	4
~~4(d)(7)~~	—	~~Sixtieth Supplemental Indenture to Exhibit 4(d)(1) dated as of July 1, 1993~~	~~HL&P’s Form 10-Q for the quarter ended June 30, 1993~~	~~1-3187~~	4
~~4(d)(8)~~	—	~~Sixty-First through Sixty-Third Supplemental Indentures to Exhibit 4(d)(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)~~
~~4(d)(9)~~	—	~~Sixty-Fourth~~President and ~~Sixty-Fifth Supplemental Indentures to Exhibit 4(d)(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)~~
~~4(e)(1)~~	—	~~General Mortgage Indenture, dated as of October 10, 2002, between CenterPoint Energy Houston Electric, LLC and JPMorgan Chase Bank, as Trustee~~	~~CenterPoint Houston’s Form 10-Q for the quarter ended September 30, 2002~~	~~1-3187~~	~~4(j)(1)~~
~~4(e)(2)~~	—	~~Second Supplemental Indenture to Exhibit 4(e)(1), dated as of October 10, 2002~~	~~CenterPoint Houston’s Form 10- Q for the quarter ended September 30, 2002~~	~~1-3187~~	~~4(j)(3)~~
~~4(e)(3)~~	—	~~Third Supplemental Indenture to Exhibit 4(e)(1), dated as of October 10, 2002~~	~~CenterPoint Houston’s Form 10-Q for the quarter ended September 30, 2002~~	~~1-3187~~	~~4(j)(4)~~
~~4(e)(4)~~	—	~~Fourth Supplemental Indenture to Exhibit 4(e)(1), dated as of October 10, 2002~~	~~CenterPoint Houston’s Form 10- Q for the quarter ended September 30, 2002~~	~~1-3187~~	~~4(j)(5)~~
~~4(e)(5)~~	—	~~Fifth Supplemental Indenture to Exhibit 4(e)(1), dated as of October 10, 2002~~	~~CenterPoint Houston’s Form 10-Q for the quarter ended September 30, 2002~~	~~1-3187~~	~~4(j)(6)~~
~~4(e)(6)~~	—	~~Sixth Supplemental Indenture to Exhibit 4(e)(1), dated as of October 10, 2002~~	~~CenterPoint Houston’s Form 10-Q for the quarter ended September 30, 2002~~	~~1-3187~~	~~4(j)(7)~~
~~4(e)(7)~~	—	~~Seventh Supplemental Indenture to Exhibit 4(e)(1), dated as of October 10, 2002~~	~~CenterPoint Houston’s Form 10-Q for the quarter ended September 30, 2002~~	~~1-3187~~	~~4(j)(8)~~
~~4(e)(8)~~	—	~~Eighth Supplemental Indenture to Exhibit 4(e)(1), dated as of October 10, 2002~~	~~CenterPoint Houston’s Form 10-Q for the quarter ended September 30, 2002~~	~~1-3187~~	~~4(j)(9)~~
~~4(e)(9)~~	—	~~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)~~
~~4(e)(10)~~	—	~~Ninth Supplemental Indenture to Exhibit 4(e)(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)~~
~~4(e)(11)~~	—	~~Officer’s Certificate dated November 12, 2003 setting forth the form, terms and provisions of the Ninth Series of General Mortgage Bonds~~	~~CenterPoint Energy’s Form 10-K for the year ended December 31, 2003~~	~~1-31447~~	~~4(e)(12)~~
~~4(e)(12)~~	—	~~Tenth Supplemental Indenture to Exhibit 4(e)(1), dated as of March 18, 2003~~	~~CenterPoint Energy’s Form 8-K dated March 13, 2003~~	~~1-31447~~	~~4.1~~
~~4(e)(13)~~	—	~~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~~
~~4(e)(14)~~	—	~~Eleventh Supplemental Indenture to Exhibit 4(e)(1), dated as of May 23, 2003~~	~~CenterPoint Energy’s Form 8-K dated May 16, 2003~~	~~1-31447~~	~~4.2~~
~~4(e)(15)~~	—	~~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~~Chief Executive Officer

~~136~~



~~4(e)(16)~~	—	~~Twelfth Supplemental Indenture to Exhibit 4(e)(1), dated as of September 9, 2003~~Signature	~~CenterPoint Energy’s Form 8-K dated September 9, 2003~~	~~1-31447~~	~~4.2~~Title
~~4(e)(17)~~	—	~~Officer’s Certificate dated September 9, 2003 setting forth the form, terms and provisions of the Thirteenth Series of General Mortgage Bonds~~	~~CenterPoint Energy’s Form 8-K dated September 9, 2003~~	~~1-31447~~	~~4.3~~
~~4(e)(18)~~	—	~~Thirteenth Supplemental Indenture to Exhibit 4(e)(1), dated as of February 6, 2004~~	~~CenterPoint Energy’s Form 10-K for the year ended December 31, 2005~~	~~1-31447~~	~~4(e)(16)~~
~~4(e)(19)~~	—	~~Officer’s Certificate dated February 6, 2004 setting forth the form, terms and provisions of the Fourteenth Series of General Mortgage Bonds~~	~~CenterPoint Energy’s Form 10-K for the year ended December 31, 2005~~	~~1-31447~~	~~4(e)(17)~~
~~4(e)(20)~~	—	~~Fourteenth Supplemental Indenture to Exhibit 4(e)(1), dated as of February 11, 2004~~	~~CenterPoint Energy’s Form 10-K for the year ended December 31, 2005~~	~~1-31447~~	~~4(e)(18)~~
~~4(e)(21)~~	—	~~Officer’s Certificate dated February 11, 2004 setting forth the form, terms and provisions of the Fifteenth Series of General Mortgage Bonds~~	~~CenterPoint Energy’s Form 10-K for the year ended December 31, 2005~~	~~1-31447~~	~~4(e)(19)~~
~~4(e)(22)~~	—	~~Fifteenth Supplemental Indenture to Exhibit 4(e)(1), dated as of March 31, 2004~~	~~CenterPoint Energy’s Form 10-K for the year ended December 31, 2005~~	~~1-31447~~	~~4(e)(20)~~
~~4(e)(23)~~	—	~~Officer’s Certificate dated March 31, 2004 setting forth the form, terms and provisions of the Sixteenth Series of General Mortgage Bonds~~	~~CenterPoint Energy’s Form 10-K for the year ended December 31, 2005~~	~~1-31447~~	~~4(e)(21)~~
~~4(e)(24)~~	—	~~Sixteenth Supplemental Indenture to Exhibit 4(e)(1), dated as of March 31, 2004~~	~~CenterPoint Energy’s Form 10-K for the year ended December 31, 2005~~	~~1-31447~~	~~4(e)(22)~~
~~4(e)(25)~~	—	~~Officer’s Certificate dated March 31, 2004 setting forth the form, terms and provisions of the Seventeenth Series of General Mortgage Bonds~~	~~CenterPoint Energy’s Form 10-K for the year ended December 31, 2005~~	~~1-31447~~	~~4(e)(23)~~
~~4(e)(26)~~	—	~~Seventeenth Supplemental Indenture to Exhibit 4(e)(1), dated as of March 31, 2004~~	~~CenterPoint Energy’s Form 10-K for the year ended December 31, 2005~~	~~1-31447~~	~~4(e)(24)~~
~~4(e)(27)~~	—	~~Officer’s Certificate dated March 31, 2004 setting forth the form, terms and provisions of the Eighteenth Series of General Mortgage Bonds~~	~~CenterPoint Energy’s Form 10-K for the year ended December 31, 2005~~	~~1-31447~~	~~4(e)(25)~~
~~4(e)(28)~~	—	~~Nineteenth Supplemental Indenture to Exhibit 4(e)(1), dated as of November 26, 2008~~	~~CenterPoint Energy’s Form 8-K dated November 25, 2008~~	~~1-31447~~	~~4.2~~
~~4(e)(29)~~	—	~~Officer’s Certificate dated November 26, 2008 setting forth the form, terms and provisions of the Twentieth Series of General Mortgage Bonds~~	~~CenterPoint Energy’s Form 8-K dated November 25, 2008~~	~~1-31447~~	~~4.3~~
~~4(e)(30)~~	—	~~Twentieth Supplemental Indenture to Exhibit 4(e)(1), dated as of December 9, 2008~~	~~CenterPoint Houston’s Form 8-K dated January 6, 2009~~	~~1-3187~~	~~4.2~~
~~4(e)(31)~~	—	~~Twenty-First Supplemental Indenture to Exhibit 4(e)(1), dated as of January 9, 2009~~	~~CenterPoint Energy’s Form 10-K for the year ended December 31, 2008~~	~~1-31447~~	~~4(e)(31)~~
~~4(e)(32)~~	—	~~Officer’s Certificate dated January 20, 2009 setting forth the form, terms and provisions of the Twenty-First Series of General Mortgage Bonds~~	~~CenterPoint Energy’s Form 10-K for the year ended December 31, 2008~~	~~1-31447~~	~~4(e)(32)~~
~~4(e)(33)~~	—	~~Twenty-Second Supplemental Indenture to Exhibit 4(e)(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)~~

~~137~~



~~4(e)(34)~~	—	~~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)~~
~~4(e)(35)~~	—	~~Twenty-Third Supplemental Indenture, dated as of March 17, 2014, to the General Mortgage Indenture, dated as of October 10, 2002, between CenterPoint Houston and the Trustee~~	~~CenterPoint Energy’s Form 10-Q for the quarter ended March 31, 2014~~	~~1-31447~~	~~4.10~~
~~4(e)(36)~~	—	~~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~~
~~4(f)(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~~
~~4(f)(2)~~	—	~~Supplemental Indenture No. 1 to Exhibit 4(f)(1), dated as of February 1, 1998, providing for the issuance of RERC Corp.’s 6 1/2% Debentures due February 1, 2008~~	~~CERC Corp.’s Form 8-K dated November 9, 1998~~	~~1-13265~~	~~4.2~~
~~4(f)(3)~~	—	~~Supplemental Indenture No. 2 to Exhibit 4(f)(1), dated as of November 1, 1998, providing for the issuance of RERC Corp.’s 6 3/8% Term Enhanced ReMarketable Securities~~	~~CERC Corp.’s Form 8-K dated November 9, 1998~~	~~1-13265~~	~~4.1~~
~~4(f)(4)~~	—	~~Supplemental Indenture No. 3 to Exhibit 4(f)(1), dated as of July 1, 2000, providing for the issuance of RERC Corp.’s 8.125% Notes due 2005~~	~~CERC Corp.’s Registration Statement on Form S-4~~	~~333-49162~~	~~4.2~~
~~4(f)(5)~~	—	~~Supplemental Indenture No. 4 to Exhibit 4(f)(1), dated as of February 15, 2001, providing for the issuance of RERC Corp.’s 7.75% Notes due 2011~~	~~CERC Corp.’s Form 8-K dated February 21, 2001~~	~~1-13265~~	~~4.1~~
~~4(f)(6)~~	—	~~Supplemental Indenture No. 5 to Exhibit 4(f)(1), dated as of March 25, 2003, providing for the issuance of CenterPoint Energy Resources Corp.’s (CERC Corp.’s) 7.875% Senior Notes due 2013~~	~~CenterPoint Energy’s Form 8-K dated March 18, 2003~~	~~1-31447~~	~~4.1~~
~~4(f)(7)~~	—	~~Supplemental Indenture No. 6 to Exhibit 4(f)(1), dated as of April 14, 2003, providing for the issuance of CERC Corp.’s 7.875% Senior Notes due 2013~~	~~CenterPoint Energy’s Form 8-K dated April 7, 2003~~	~~1-31447~~	~~4.2~~
~~4(f)(8)~~	—	~~Supplemental Indenture No. 7 to Exhibit 4(f)(1), dated as of November 3, 2003, providing for the issuance of CERC Corp.’s 5.95% Senior Notes due 2014~~	~~CenterPoint Energy’s Form 8-K dated October 29, 2003~~	~~1-31447~~	~~4.2~~
~~4(f)(9)~~	—	~~Supplemental Indenture No. 8 to Exhibit 4(f)(1), dated as of December 28, 2005, providing for a modification of CERC Corp.’s 6 1/2% Debentures due 2008~~	~~CenterPoint Energy’s Form 10-K for the year ended December 31, 2005~~	~~1-31447~~	~~4(f)(9)~~
~~4(f)(10)~~	—	~~Supplemental Indenture No. 9 to Exhibit 4(f)(1), dated as of May 18, 2006, providing for the issuance of CERC Corp.’s 6.15% Senior Notes due 2016~~	~~CenterPoint Energy’s Form 10-Q for the quarter ended June 30, 2006~~	~~1-31447~~	~~4.7~~
~~4(f)(11)~~	—	~~Supplemental Indenture No. 10 to Exhibit 4(f)(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)~~
~~4(f)(12)~~	—	~~Supplemental Indenture No. 11 to Exhibit 4(f)(1) dated as of October 23, 2007, providing for the issuance of CERC Corp.’s 6.125% Senior Notes due 2017~~	~~CenterPoint Energy’s Form 10-Q for the quarter ended September 30, 2007~~	~~1-31447~~	~~4.8~~

~~138~~



~~4(f)(13)~~	—	~~Supplemental Indenture No. 12 to Exhibit 4(f)(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~~
~~4(f)(14)~~	—	~~Supplemental Indenture No. 13 to Exhibit 4(f)(1) dated as of May 15, 2008, providing for the issuance of CERC Corp.’s 6.00% Senior Notes due 2018~~	~~CenterPoint Energy’s Form 10-Q for the quarter ended June 30, 2008~~	~~1-31447~~	~~4.9~~
~~4(f)(15)~~	—	~~Supplemental Indenture No. 14 to Exhibit 4(f)(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)~~
~~4(f)(16)~~	—	~~Supplemental Indenture No. 15 to Exhibit 4(f)(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)~~
~~4(g)(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~~
~~4(g)(2)~~	—	~~Supplemental Indenture No. 1 to Exhibit 4(g)(1), dated as of May 19, 2003, providing for the issuance of CenterPoint Energy’s 3.75% Convertible Senior Notes due 2023~~	~~CenterPoint Energy’s Form 8-K dated May 19, 2003~~	~~1-31447~~	~~4.2~~
~~4(g)(3)~~	—	~~Supplemental Indenture No. 2 to Exhibit 4(g)(1), dated as of May 27, 2003, providing for the issuance of CenterPoint Energy’s 5.875% Senior Notes due 2008 and 6.85% Senior Notes due 2015~~	~~CenterPoint Energy’s Form 8-K dated May 19, 2003~~	~~1-31447~~	~~4.3~~
~~4(g)(4)~~	—	~~Supplemental Indenture No. 3 to Exhibit 4(g)(1), dated as of September 9, 2003, providing for the issuance of CenterPoint Energy’s 7.25% Senior Notes due 2010~~	~~CenterPoint Energy’s Form 8-K dated September 9, 2003~~	~~1-31447~~	~~4.2~~
~~4(g)(5)~~	—	~~Supplemental Indenture No. 4 to Exhibit 4(g)(1), dated as of December 17, 2003, providing for the issuance of CenterPoint Energy’s 2.875% Convertible Senior Notes due 2024~~	~~CenterPoint Energy’s Form 8-K dated December 10, 2003~~	~~1-31447~~	~~4.2~~
~~4(g)(6)~~	—	Supplemental Indenture No. 5 to Exhibit 4(g)(1), dated as of December 13, 2004, as supplemented by Exhibit 4(g)(5), relating to the issuance of CenterPoint Energy’s 2.875% Convertible Senior Notes due 2024	~~CenterPoint Energy’s Form 8-K dated December 9, 2004~~	~~1-31447~~	~~4.1~~
~~4(g)(7)~~	—	~~Supplemental Indenture No. 6 to Exhibit 4(g)(1), dated as of August 23, 2005, providing for the issuance of CenterPoint Energy’s 3.75% Convertible Senior Notes, Series B due 2023~~	~~CenterPoint Energy’s Form 10-K for the year ended December 31, 2005~~	~~1-31447~~	~~4(g)(7)~~
~~4(g)(8)~~	—	~~Supplemental Indenture No. 7 to Exhibit 4(g)(1), dated as of February 6, 2007, providing for the issuance of CenterPoint Energy’s 5.95% Senior Notes due 2017~~	~~CenterPoint Energy’s Form 10-K for the year ended December 31, 2006~~	~~1-31447~~	~~4(g)(8)~~
~~4(g)(9)~~	—	~~Supplemental Indenture No. 8 to Exhibit 4(g)(1), dated as of May 5, 2008, providing for the issuance of CenterPoint Energy’s 6.50% Senior Notes due 2018~~	~~CenterPoint Energy’s Form 10-Q for the quarter ended June 30, 2008~~	~~1-31447~~	~~4.7~~
~~4(h)(1)~~	—	~~Subordinated Indenture dated as of September 1, 1999~~	~~Reliant Energy’s Form 8-K dated September 1, 1999~~	~~1-3187~~	~~4.1~~

~~139~~



~~4(h)(2)~~	—	Supplemental Indenture No. 1 dated as of September 1, 1999, between Reliant Energy and Chase Bank of Texas (supplementing Exhibit 4(h)(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~~
~~4(h)(3)~~	—	~~Supplemental Indenture No. 2 dated as of August 31, 2002, between CenterPoint Energy, Reliant Energy and JPMorgan Chase Bank (supplementing Exhibit 4(h)(1))~~	~~CenterPoint Energy’s Form 8-K12B dated August 31, 2002~~	~~1-31447~~	~~4(e)~~
~~4(h)(4)~~	—	~~Supplemental Indenture No. 3 dated as of December 28, 2005, between CenterPoint Energy, Reliant Energy and JPMorgan Chase Bank (supplementing Exhibit 4(h)(1))~~	~~CenterPoint Energy’s Form 10-K for the year ended December 31, 2005~~	~~1-31447~~	~~4(h)(4)~~
~~4(i)(1)~~	—	~~$1,200,000,000 Credit Agreement dated as of September 9, 2011, among CenterPoint Energy, as Borrower, and the banks named therein~~	~~CenterPoint Energy’s Form 8-K dated September 9, 2011~~	~~1-31447~~	~~4.1~~
~~4(i)(2)~~	—	~~First Amendment to Credit Agreement, dated as of April 11, 2013, among CenterPoint Energy, as Borrower, and the banks named therein~~	~~CenterPoint Energy’s Form 8-K dated April 11, 2013~~	~~1-31447~~	~~4.1~~
~~4(i)(3)~~	—	~~Second Amendment to Credit Agreement, dated as of September 9, 2013, among CenterPoint Energy, as Borrower, and the banks named therein~~	~~CenterPoint Energy’s Form 8-K dated September 9, 2013~~	~~1-31447~~	~~4.1~~
~~4(i)(4)~~	—	~~Third Amendment to Credit Agreement, dated as of September 9, 2014, among CenterPoint Energy, as Borrower, and the banks named therein~~	~~CenterPoint Energy’s Form 8-K dated September 10, 2014~~	~~1-31447~~	~~4.1~~
~~4(j)(1)~~	—	~~$300,000,000 Credit Agreement dated as of September 9, 2011, among CenterPoint Houston, as Borrower, and the banks named therein~~	~~CenterPoint Energy’s Form 8-K dated September 9, 2011~~	~~1-31447~~	~~4.2~~
~~4(j)(2)~~	—	~~First Amendment to Credit Agreement, dated as of September 9, 2013, among CenterPoint Houston, as Borrower, and the banks named therein~~	~~CenterPoint Energy’s Form 8-K dated September 9, 2013~~	~~1-31447~~	~~4.2~~
~~4(j)(3)~~	—	~~Second Amendment to Credit Agreement, dated as of September 9, 2014, among CenterPoint Houston, as Borrower, and the banks named therein~~	~~CenterPoint Energy’s Form 8-K dated September 10, 2014~~	~~1-31447~~	~~4.2~~
~~4(k)~~	—	~~$950,000,000 Credit Agreement dated as of September 9, 2011, among CERC Corp., as Borrower, and the banks named therein~~	~~CenterPoint Energy’s Form 8-K dated September 9, 2011~~	~~1-31447~~	~~4.3~~
~~4(k)(2)~~	—	~~First Amendment to Credit Agreement, dated as of April 11, 2013, among CERC Corp., as Borrower, and the banks named therein~~	~~CenterPoint Energy’s Form 8-K dated April 11, 2013~~	~~1-31447~~	~~4.2~~
~~4(k)(3)~~	—	~~Second Amendment to Credit Agreement, dated as of September 9, 2013, among CERC Corp., as Borrower, and the banks named therein~~	~~CenterPoint Energy’s Form 8-K dated September 9, 2013~~	~~1-31447~~	~~4.3~~
~~4(k)(4)~~	—	~~Third Amendment to Credit Agreement, dated as of September 9, 2014, among CERC Corp., as Borrower, and the banks named therein~~	~~CenterPoint Energy’s Form 8-K dated September 10, 2014~~	~~1-31447~~	~~4.3~~

Pursuant to Item 601(b)(4)(iii)(A) of Regulation S-K, CenterPoint Energy has not filed as exhibits to this Form 10-K certain long-term debt instruments, including indentures, under which the total amount of securities authorized does not exceed 10% of the total assets of CenterPoint Energy and its subsidiaries on a consolidated basis. CenterPoint Energy hereby agrees to furnish a copy of any such instrument to the SEC upon request.

~~140~~



~~Exhibit~~ ~~Number~~		~~Description~~	~~Report or Registration Statement~~	~~SEC File or~~ ~~Registration~~ ~~Number~~	~~Exhibit~~ ~~Reference~~
*10(a)	—	~~CenterPoint Energy Executive Benefits Plan, as amended and restated effective June 18, 2003~~	~~CenterPoint Energy’s Form 10-Q for the quarter ended September 30, 2003~~	~~1-31447~~	~~10.4~~
*10(b)(1)	—	~~Executive Incentive Compensation Plan of Houston Industries Incorporated (HI) effective as of January 1, 1982~~	~~HI’s Form 10-K for the year ended December 31, 1991~~	~~1-7629~~	~~10(b)~~
*10(b)(2)	—	~~First Amendment to Exhibit 10(b)(1) effective as of March 30, 1992~~	~~HI’s Form 10-Q for the quarter ended March 31, 1992~~	~~1-7629~~	~~10(a)~~
*10(b)(3)	—	~~Second Amendment to Exhibit 10(b)(1) effective as of November 4, 1992~~	~~HI’s Form 10-K for the year ended December 31, 1992~~	~~1-7629~~	~~10(b)~~
*10(b)(4)	—	~~Third Amendment to Exhibit 10(b)(1) effective as of September 7, 1994~~	~~HI’s Form 10-K for the year ended December 31, 1994~~	~~1-7629~~	~~10(b)(4)~~
*10(b)(5)	—	~~Fourth Amendment to Exhibit 10(b)(1) effective as of August 6, 1997~~	~~HI’s Form 10-K for the year ended December 31, 1997~~	~~1-3187~~	~~10(b)(5)~~
*10(c)(1)	—	~~Executive Incentive Compensation Plan of HI as amended and restated on January 1, 1991~~	~~HI’s Form 10-K for the year ended December 31, 1990~~	~~1-7629~~	~~10(b)~~
*10(c)(2)	—	~~First Amendment to Exhibit 10(c)(1) effective as of January 1, 1991~~	~~HI’s Form 10-K for the year ended December 31, 1991~~	~~1-7629~~	~~10(f)(2)~~
*10(c)(3)	—	~~Second Amendment to Exhibit 10(c)(1) effective as of March 30, 1992~~	~~HI’s Form 10-Q for the quarter ended March 31, 1992~~	~~1-7629~~	~~10(d)~~
*10(c)(4)	—	~~Third Amendment to Exhibit 10(c)(1) effective as of November 4, 1992~~	~~HI’s Form 10-K for the year ended December 31, 1992~~	~~1-7629~~	~~10(f)(4)~~
*10(c)(5)	—	~~Fourth Amendment to Exhibit 10(c)(1) effective as of January 1, 1993~~	~~HI’s Form 10-K for the year ended December 31, 1992~~	~~1-7629~~	~~10(f)(5)~~
*10(c)(6)	—	~~Fifth Amendment to Exhibit 10(c)(1) effective in part, January 1, 1995, and in part, September 7, 1994~~	~~HI’s Form 10-K for the year ended December 31, 1994~~	~~1-7629~~	~~10(f)(6)~~
*10(c)(7)	—	~~Sixth Amendment to Exhibit 10(c)(1) effective as of August 1, 1995~~	~~HI’s Form 10-Q for the quarter ended June 30, 1995~~	~~1-7629~~	~~10(a)~~
*10(c)(8)	—	~~Seventh Amendment to Exhibit 10(c)(1) effective as of January 1, 1996~~	~~HI’s Form 10-Q for the quarter ended June 30, 1996~~	~~1-7629~~	~~10(a)~~
*10(c)(9)	—	~~Eighth Amendment to Exhibit 10(c)(1) effective as of January 1, 1997~~	~~HI’s Form 10-Q for the quarter ended June 30, 1997~~	~~1-7629~~	~~10(a)~~
*10(c)(10)	—	~~Ninth Amendment to Exhibit 10(c)(1) effective in part, January 1, 1997, and in part, January 1, 1998~~	~~HI’s Form 10-K for the year ended December 31, 1997~~	~~1-3187~~	~~10(f)(10)~~
*10(d)	—	~~Benefit Restoration Plan of HI effective as of June 1, 1985~~	~~HI’s Form 10-Q for the quarter ended March 31, 1987~~	~~1-7629~~	~~10(c)~~
*10(e)	—	~~Benefit Restoration Plan of HI as amended and restated effective as of January 1, 1988~~	~~HI’s Form 10-K for the year ended December 31, 1991~~	~~1-7629~~	~~10(g)(2)~~
*10(f)	—	~~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~~
*10(g)(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~~
*10(g)(2)	—	~~First Amendment to Exhibit 10(g)(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~~
*10(h)(1)	—	~~HI 1995 Section 415 Benefit Restoration Plan effective August 1, 1995~~	~~CenterPoint Energy’s Form 10-K for the year ended December 31, 2008~~	~~1-31447~~	~~10(h)(1)~~
*10(h)(2)	—	~~First Amendment to Exhibit 10(h)(1) effective as of August 1, 1995~~	~~CenterPoint Energy’s Form 10-K for the year ended December 31, 2008~~	~~1-31447~~	~~10(h)(2)~~

~~141~~



*10(i)	—	~~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~~
*10(j)(1)	—	~~Reliant Energy 1994 Long- Term Incentive Compensation Plan, as amended and restated effective January 1, 2001~~	~~Reliant Energy’s Form 10-Q for the quarter ended June 30, 2002~~	~~1-3187~~	~~10.6~~
*10(j)(2)	—	~~First Amendment to Exhibit 10(j)(1), effective December 1, 2003~~	~~CenterPoint Energy’s Form 10-K for the year ended December 31, 2003~~	~~1-31447~~	~~10(p)(7)~~
*10(j)(3)	—	~~Form of Non-Qualified Stock Option Award Notice under Exhibit 10(i)(1)~~	~~CenterPoint Energy’s Form 8-K dated January 25, 2005~~	~~1-31447~~	~~10.6~~
*10(k)(1)	—	~~Savings Restoration Plan of HI effective as of January 1, 1991~~	~~HI’s Form 10-K for the year ended December 31, 1990~~	~~1-7629~~	~~10(f)~~
*10(k)(2)	—	~~First Amendment to Exhibit 10(k)(1) effective as of January 1, 1992~~	~~HI’s Form 10-K for the year ended December 31, 1991~~	~~1-7629~~	~~10(l)(2)~~
*10(k)(3)	—	~~Second Amendment to Exhibit 10(k)(1) effective in part, August 6, 1997, and in part, October 1, 1997~~	~~HI’s Form 10-K for the year ended December 31, 1997~~	~~1-3187~~	~~10(q)(3)~~
*10(l)(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~~
*10(l)(2)	—	~~First Amendment to Exhibit 10(l)(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~~
*10(m)(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~~
*10(m)(2)	—	~~First Amendment to Exhibit 10(m)(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~~
*10(n)(1)	—	~~CenterPoint Energy Outside Director Benefits Plan, as amended and restated effective June 18, 2003~~	~~CenterPoint Energy’s Form 10-Q for the quarter ended September 30, 2003~~	~~1-31447~~	~~10.6~~
*10(n)(2)	—	~~First Amendment to Exhibit 10(n)(1) effective as of January 1, 2004~~	~~CenterPoint Energy’s Form 10-Q for the quarter ended June 30, 2004~~	~~1-31447~~	~~10.6~~
*10(n)(3)	—	~~CenterPoint Energy Outside Director Benefits Plan, as amended and restated effective December 31, 2008~~	~~CenterPoint Energy’s Form 10-K for the year ended December 31, 2008~~	~~1-31447~~	~~10(n)(3)~~
*10(o)	—	~~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~~
*10(p)	—	~~Employment and Supplemental Benefits Agreement between HL&P and Hugh Rice Kelly~~	~~HI’s Form 10-Q for the quarter ended March 31, 1987~~	~~1-7629~~	~~10(f)~~
~~10(q)(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
~~10(q)(2)~~	—	~~Amendment to Exhibit 10(q)(1) dated November 18, 1996~~	~~HI’s Form 10-K for the year ended December 31, 1996~~	~~1-7629~~	~~10(x)(4)~~
*10(r)(1)	—	~~Houston Industries Incorporated Executive Deferred Compensation Trust effective as of December 19, 1995~~	~~HI’s Form 10-K for the year ended December 31, 1995~~	~~1-7629~~	~~10(7)~~
*10(r)(2)	—	~~First Amendment to Exhibit 10(r)(1) effective as of August 6, 1997~~	~~HI’s Form 10-Q for the quarter ended June 30, 1998~~	~~1-3187~~	10
~~†10(s)~~	—	~~Summary of Certain Compensation Arrangements of the Executive Chairman of the Board~~

~~142~~



*10(t)	—	~~Reliant Energy, Incorporated and Subsidiaries Common Stock Participation Plan for Designated New Employees and Non-Officer Employees, as amended and restated effective January 1, 2001~~	~~CenterPoint Energy’s Form 10-K for the year ended December 31, 2002~~	~~1-31447~~	~~10(y)(2)~~
*10(u)(1)	—	~~Long-Term Incentive Plan of CenterPoint Energy, Inc. (amended and restated effective as of May 1, 2004)~~	~~CenterPoint Energy’s Form 10-Q for the quarter ended June 30, 2004~~	~~1-31447~~	~~10.5~~
*10(u)(2)	—	~~First Amendment to Exhibit (u)(1), effective January 1, 2007~~	~~CenterPoint Energy’s Form 10-Q for the quarter ended March 31, 2007~~	~~1-31447~~	~~10.5~~
*10(u)(3)	—	~~Form of Non-Qualified Stock Option Award Agreement under Exhibit 10(u)(1)~~	~~CenterPoint Energy’s Form 8-K dated January 25, 2005~~	~~1-31447~~	~~10.1~~
*10(u)(4)	—	~~Form of Restricted Stock Award Agreement under Exhibit 10(u)(1)~~	~~CenterPoint Energy’s Form 8-K dated January 25, 2005~~	~~1-31447~~	~~10.2~~
*10(u)(5)	—	~~Form of Performance Share Award under Exhibit 10(u)(1)~~	~~CenterPoint Energy’s Form 8-K dated January 25, 2005~~	~~1-31447~~	~~10.3~~
*10(u)(6)	—	~~Form of Performance Share Award Agreement for 20XX-20XX Performance Cycle under Exhibit 10(u)(1)~~	~~CenterPoint Energy’s Form 8-K dated February 22, 2006~~	~~1-31447~~	~~10.2~~
*10(u)(7)	—	~~Form of Restricted Stock Award Agreement (With Performance Vesting Requirement) under Exhibit 10(u)(1)~~	~~CenterPoint Energy’s Form 8-K dated February 21, 2005~~	~~1-31447~~	~~10.2~~
*10(u)(8)	—	~~Form of Stock Award Agreement (With Performance Goal) under Exhibit 10(u)(1)~~	~~CenterPoint Energy’s Form 8-K dated February 22, 2006~~	~~1-31447~~	~~10.3~~
*10(u)(9)	—	~~Form of Performance Share Award Agreement for 20XX — 20XX Performance Cycle under Exhibit 10(u)(1)~~	~~CenterPoint Energy’s Form 8-K dated February 21, 2007~~	~~1-31447~~	~~10.1~~
*10(u)(10)	—	~~Form of Stock Award Agreement (With Performance Goal) under Exhibit 10(u)(1)~~	~~CenterPoint Energy’s Form 8-K dated February 21, 2007~~	~~1-31447~~	~~10.2~~
*10(u)(11)	—	~~Form of Stock Award Agreement (Without Performance Goal) under Exhibit 10(u)(1)~~	~~CenterPoint Energy’s Form 8-K dated February 21, 2007~~	~~1-31447~~	~~10.3~~
*10(u)(12)	—	~~Form of Performance Share Award Agreement for 20XX — 20XX Performance Cycle under Exhibit 10(u)(1)~~	~~CenterPoint Energy’s Form 8-K dated February 20, 2008~~	~~1-31447~~	~~10.1~~
*10(u)(13)	—	~~Form of Stock Award Agreement (With Performance Goal) under Exhibit 10(u)(1)~~	~~CenterPoint Energy’s Form 8-K dated February 20, 2008~~	~~1-31447~~	~~10.2~~
~~10(v)(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~~
~~10(v)(2)~~	—	~~First Amendment to Exhibit 10(v)(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)~~
~~10(v)(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~~
~~10(v)(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~~
~~10(v)(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~~
~~10(w)(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)~~
~~10(w)(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)~~
~~10(w)(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)~~

~~143~~



*10(x)	—	~~Retention Agreement effective October 15, 2001 between Reliant Energy and David G. Tees~~	~~Reliant Energy’s Form 10-K for the year ended December 31, 2001~~	~~1-3187~~	~~10(jj)~~
*10(y)	—	~~Retention Agreement effective October 15, 2001 between Reliant Energy and Michael A. Reed~~	~~Reliant Energy’s Form 10-K for the year ended December 31, 2001~~	~~1-3187~~	~~10(kk)~~
*10(z)	—	~~Non-Qualified Unfunded Executive Supplemental Income Retirement Plan of Arkla, Inc. effective as of August 1, 1983~~	~~CenterPoint Energy’s Form 10-K for the year ended December 31, 2002~~	~~1-31447~~	~~10(gg)~~
*10(aa)(1)	—	~~Deferred Compensation Plan for Directors of Arkla, Inc. effective as of November 10, 1988~~	~~CenterPoint Energy’s Form 10-K for the year ended December 31, 2002~~	~~1-31447~~	~~10(hh)(1)~~
*10(aa)(2)	—	~~First Amendment to Exhibit 10(aa)(1) effective as of August 6, 1997~~	~~CenterPoint Energy’s Form 10-K for the year ended December 31, 2002~~	~~1-31447~~	~~10(hh)(2)~~
*10(bb)(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~~
*10(bb)(2)	—	~~First Amendment to Exhibit 10(bb)(1) effective as of January 1, 2008~~	~~CenterPoint Energy’s Form 8-K dated February 20, 2008~~	~~1-31447~~	~~10.4~~
*10(bb)(3)	—	~~CenterPoint Energy 2005 Deferred Compensation Plan, effective January 1, 2008~~	~~CenterPoint Energy’s Form 8-K dated February 20, 2008~~	~~1-31447~~	~~10.3~~
*10(bb)(4)	—	~~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~~
*10(cc)(1)	—	~~CenterPoint Energy Short Term Incentive Plan, as amended and restated effective January 1, 2003~~	~~CenterPoint Energy’s Form 10-Q for the quarter ended September 30, 2003~~	~~1-31447~~	~~10.3~~
*10(cc)(2)	—	~~Second Amendment to Exhibit 10(cc)(1)~~	~~CenterPoint Energy’s Form 8-K dated December 10, 2009~~	~~1-31447~~	~~10.1~~
*10(dd)(1)	—	~~CenterPoint Energy Stock Plan for Outside Directors, as amended and restated effective May 7, 2003~~	~~CenterPoint Energy’s Form 10-K for the year ended December 31, 2003~~	~~1-31447~~	~~10(ll)~~
*10(dd)(2)	—	~~First Amendment to Exhibit 10(dd)(1)~~	~~CenterPoint Energy’s Form 10-Q for the quarter ended March 31, 2010~~	~~1-31447~~	~~10.2~~
*10(dd)(3)	—	~~Second Amendment to Exhibit 10(dd)(1)~~	~~CenterPoint Energy’s Registration Statement on Form S-8~~	~~333-173660~~	~~4.6~~
*10(dd)(4)	—	~~Third Amendment to Exhibit 10(dd)(1)~~	~~CenterPoint Energy’s Form 10-K for the year ended December 31, 2014~~	~~1-31447~~	~~10(dd)(4)~~
~~10(ee)~~	—	~~City of Houston Franchise Ordinance~~	~~CenterPoint Energy’s Form 10-Q for the quarter ended June 30, 2005~~	~~1-31447~~	~~10.1~~
~~10(ff)~~	—	~~Letter Agreement dated March 16, 2006 between CenterPoint Energy and John T. Cater~~	~~CenterPoint Energy’s Form 10-Q for the quarter ended March 30, 2006~~	~~1-31447~~	10
~~10(gg)(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~~
~~10(gg)(2)~~	—	~~First Amendment to Exhibit 10(gg)(1) effective as of January 1, 2008~~	~~CenterPoint Energy’s Form 10-Q for the quarter ended September 30, 2008~~	~~1-31447~~	~~10.3~~
*10(hh)(1)	—	~~Executive Benefits Agreement by and between HL&P and Thomas R. Standish effective August 20, 1993~~	~~CenterPoint Energy’s Form 10-K for the year ended December 31, 2008~~	~~1-31447~~	~~10(hh)(1)~~
*10(hh)(2)	—	~~First Amendment to Exhibit 10(hh)(1) effective as of December 31, 2008~~	~~CenterPoint Energy’s Form 10-K for the year ended December 31, 2008~~	~~1-31447~~	~~10(hh)(2)~~
*10(ii)(1)	—	~~Executive Benefits Agreement by and between HL&P and David M. McClanahan effective August 24, 1993~~	~~CenterPoint Energy’s Form 10-K for the year ended December 31, 2008~~	~~1-31447~~	~~10(ii)(1)~~
*10(ii)(2)	—	~~First Amendment to Exhibit 10(ii)(1) effective as of December 31, 2008~~	~~CenterPoint Energy’s Form 10-K for the year ended December 31, 2008~~	~~1-31447~~	~~10(ii)(2)~~
*10(jj)(1)	—	~~Executive Benefits Agreement by and between HL&P and Joseph B. McGoldrick effective August 30, 1993~~	~~CenterPoint Energy’s Form 10-K for the year ended December 31, 2008~~	~~1-31447~~	~~10(jj)(1)~~

~~144~~



*10(jj)(2)	—	~~First Amendment to Exhibit 10(jj)(1) effective as of December 31, 2008~~	~~CenterPoint Energy’s Form 10-K for the year ended December 31, 2008~~	~~1-31447~~	~~10(jj)(2)~~
*10(kk)(1)	—	~~Letter Agreement dated January 23, 2015 between CenterPoint Energy and William D. Rogers~~	~~CenterPoint Energy’s Form 10-K for the year ended December 31, 2014~~	~~1-31447~~	~~10(kk)(1)~~
*10(ll)(1)	—	~~CenterPoint Energy, Inc. 2009 Long Term Incentive Plan~~	~~CenterPoint Energy’s Schedule 14A dated March 13, 2009~~	~~1-31447~~	A
*†10(ll)(2)	—	~~Form of Qualified Performance Award Agreement for 20XX — 20XX Performance Cycle under Exhibit 10(ll)(1)~~
*†10(ll)(3)	—	~~Form of Qualified Performance Award Agreement for Executive Chairman 20XX — 20XX Performance Cycle under Exhibit 10(ll)(1)~~/s/ SCOTT M. PROCHAZKA	Chairman, President and Chief Executive Officer
(Scott M. Prochazka)		(Principal Executive Officer and Director)

*10(ll)(4)	—	~~Form of Restricted Stock Unit Award Agreement (With Performance Goal) under Exhibit 10(ll)(1)~~/s/ WILLIAM D. ROGERS	~~CenterPoint Energy’s Form 8-K dated February 28, 2012~~Executive Vice President and Chief Financial Officer
(William D. Rogers)		~~1-31447~~	~~10.2~~(Principal Financial Officer)
*†10(ll)(5)	—	~~Form of Restricted Stock Unit Award Agreement (Service-Based Vesting) under Exhibit 10(ll)(1)~~
*10(ll)(6)	—	~~Form of Restricted Stock Unit Award Agreement (Retention, Service-Based Vesting) under Exhibit 10(ll)(1)~~/s/ KRISTIE L. COLVIN	~~CenterPoint Energy’s Form 10-K for the year ended December 31, 2014~~Senior Vice President and Chief Accounting Officer
(Kristie L. Colvin)		~~1-31447~~	~~10(ll)(6)~~
*†10(ll)(7)	—	~~Form of Executive Chairman Restricted Stock Unit Award Agreement (Service-Based Vesting) under Exhibit 10(ll)(1)~~
*10(ll)(8)	—	~~Form of Executive Chairman Restricted Stock Unit Award Agreement (Retention, Service-Based Vesting) under Exhibit 10(ll)(1)~~	~~CenterPoint Energy’s Form 10-K for the year ended December 31, 2014~~	~~1-31447~~	~~10(ll)(8)~~
~~†10(mm)~~	—	~~Summary of Non-Employee Director Compensation~~
~~†10(nn)~~	—	~~Summary of Senior Executive Officer Compensation~~
~~10(oo)~~	—	~~Form of Executive Officer Change in Control Agreement~~	~~CenterPoint Energy’s Form 10-K for the year ended December 31, 2008~~	~~1-31447~~	~~10(nn)~~
~~10(pp)~~	—	~~Form of Corporate Officer Change in Control Agreement~~	~~CenterPoint Energy’s Form 10-K for the year ended December 31, 2008~~	~~1-31447~~	~~10(oo)~~
~~10(qq)~~	—	~~Change in Control Plan~~	~~CenterPoint Energy’s Form 8-K/A dated December 11, 2014~~	~~1-31447~~	~~10.1~~
~~10(rr)~~	—	~~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~~
~~10(ss)~~	—	Commitment Letter dated March 14, 2013 by and among CenterPoint Energy, Enogex LLC, Citigroup Global Markets Inc., UBS Loan Finance LLC and UBS Securities LLC relating to a $1,050,000,000 3-year unsecured term loan facility	~~CenterPoint Energy’s Form 8-K dated March 14, 2013~~	~~1-31447~~	~~10.1~~
~~10(tt)~~	—	Commitment Letter dated March 14, 2013 by and among CenterPoint Energy, Inc., Enogex LLC, Citigroup Global Markets Inc., UBS Loan Finance LLC and UBS Securities LLC relating to a $1,400,000,000 5-year unsecured revolving credit facility	~~CenterPoint Energy’s Form 8-K dated March 14, 2013~~	~~1-31447~~	~~10.2~~
~~10(uu)~~	—	~~First Amended and Restated Agreement of Limited Partnership of CEFS dated as of May 1, 2013~~	~~CenterPoint Energy’s Form 8-K dated May 1, 2013~~	~~1-31447~~	~~10.1~~
~~10(vv)~~	—	~~First Amendment to the First Amended and Restated Agreement of Limited Partnership of CEFS dated as of July 30, 2013~~	~~CenterPoint Energy’s Form 10-Q for the quarter ended September 30, 2013~~	~~1-31447~~	~~10.1~~
~~10(ww)~~	—	~~Second Amended and Restated Agreement of Limited Partnership of Enable Midstream Partners, LP dated April 16, 2014~~	~~CenterPoint Energy’s Form 8-K dated April 16, 2014~~	~~1-31447~~	~~10.1~~

~~145~~

10(xx) — Amended and Restated Limited Liability Company Agreement of CNP OGE GP LLC dated as of May 1, 2013 CenterPoint Energy’s Form 8-K dated May 1, 2013 1-31447 10.2
10(yy)(1) — Second Amended and Restated Limited Liability Company Agreement of Enable GP, LLC dated as of July 30, 2013 CenterPoint Energy’s Form 10-Q for the quarter ended September 30, 2013 1-31447 10.2
10(yy)(2) — First Amendment to the Second Amended and Restated Limited Liability Company Agreement of Enable GP, LLC dated as of April 16, 2014 CenterPoint Energy’s Form 8-K dated April 16, 2014 1-31447 10.2
10(zz) — Registration Rights Agreement dated as of May 1, 2013 by and among 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
10(aaa) — 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
10(bbb) — Agreement, dated June 26, 2013, by and between CERC Corp. and C. Gregory Harper CenterPoint Energy’s Form 10-Q for the quarter ended June 30, 2013 1-31447 10.6
10(ccc) — 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)
10(ddd) — 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
10(eee) — Third Amended and Restated Agreement of Limited Partnership of Enable Midstream Partners, LP dated February 18, 2016 CenterPoint Energy’s Form 8-K dated February 18, 2016 1-31447 10.1
10(fff) — 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
†12 — Computation of Ratio of Earnings to Fixed Charges
†21 — Subsidiaries of CenterPoint Energy
†23.1 — Consent of Deloitte & Touche LLP
†23.2 — Consent of Deloitte & Touche LLP, Independent Registered Public Accounting Firm of Enable Midstream Partners, LP
†31.1 — Rule 13a-14(a)/15d-14(a) Certification of Scott M. Prochazka
†31.2 — Rule 13a-14(a)/15d-14(a) Certification of William D. Rogers
†32.1 — Section 1350 Certification of Scott M. Prochazka
†32.2 — Section 1350 Certification of William D. Rogers
99.1 — $1,400,000,000 Credit Agreement, dated as of May 1, 2013, among CEFS as Borrower, and the banks named therein CenterPoint Energy’s Form 8-K dated May 1, 2013 1-31447 99.2
99.2 — First Amendment and Waiver to Revolving Credit Agreement dated as of January 23, 2014 by and among Enable Midstream Partners, LP, the lenders party thereto and Citibank, N.A., as agent CenterPoint Energy’s Form 10-K for the year ended December 31, 2013 1-31447 99.3
99.3 — Financial Statements of Enable Midstream Partners, LP as of December 31, 2015 and 2014 and for the years ended December 31, 2015, 2014 and 2013 Part II, Item 8 of Enable Midstream Partners, LP’s Form 10-K for the year ended December 31, 2015 001-36413 Item 8
†101.INS — XBRL Instance Document
†101.SCH — XBRL Taxonomy Extension Schema Document
†101.CAL — XBRL Taxonomy Extension Calculation Linkbase Document
†101.DEF — XBRL Taxonomy Extension Definition Linkbase Document
†101.LAB — XBRL Taxonomy Extension Labels Linkbase Document

~~146~~



~~†101.PRE~~	—	~~XBRL Taxonomy Extension Presentation Linkbase Document~~	(Principal Accounting Officer)

~~147~~185



	Market Price				Dividend Declared
	High		Low		Per Share
2015
First Quarter					$	0.2475
January 2	$	23.63
March 31			$	20.41
Second Quarter					$	0.2475
April 15	$	21.31
June 30			$	19.03
Third Quarter					$	0.2475
August 14	$	19.92
September 29			$	17.53
Fourth Quarter					$	0.2475
October 22	$	19.13
December 10			$	16.14

2014
First Quarter					$	0.2375
January 3			$	22.81
February 21	$	24.48
Second Quarter					$	0.2375
April 7			$	23.39
June 30	$	25.54
Third Quarter					$	0.2375
July 1	$	25.38
August 6			$	23.56
Fourth Quarter					$	0.2375
November 10	$	25.38
December 15			$	21.54



	Year Ended
	December 31, 2013 (1)
	(in millions, except throughput data)
Revenues	$	186
Expenses:
Natural gas	35
Operation and maintenance	51
Depreciation and amortization	20
Taxes other than income taxes	8
Total expenses	114
Operating Income	$	72

Equity in earnings of unconsolidated affiliates	$	7

Transportation throughput (in Bcf)	482



	Year Ended December 31,
	2015 (2)			2014 (3)		2013 (4)
	(in millions)
Enable (1)	$	(1,633	)	$	303	$	173
SESH	—			5		8
Total	$	(1,633	)	$	308	$	181



	December 31, 2015		December 31, 2014
	(in millions)
ASSETS
Current Assets:
Cash and cash equivalents ($264 and $290 related to VIEs, respectively)	$	264	$	298
Investment in marketable securities	805		930
Accounts receivable ($64 and $58 related to VIEs, respectively), less bad debt reserve of $20 and $26, respectively	593		837
Accrued unbilled revenues	279		357
Inventory	347		379
Non-trading derivative assets	89		99
Taxes receivable	172		190
Prepaid expense and other current assets ($35 and $47 related to VIEs, respectively)	140		178
Total current assets	2,689		3,268
Property, Plant and Equipment, net	11,537		10,502
Other Assets:
Goodwill	840		840
Regulatory assets ($2,373 and $2,738 related to VIEs, respectively)	3,129		3,527
Notes receivable - affiliated companies	363		363
Non-trading derivative assets	36		32
Investment in unconsolidated affiliates	2,594		4,521
Other	146		147
Total other assets	7,108		9,430
Total Assets	$	21,334	$	23,200
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities:
Short-term borrowings	$	40	$	53
Current portion of VIE transition and system restoration bonds long-term debt	391		372
Indexed debt	154		152
Current portion of other long-term debt	328		271
Indexed debt securities derivative	442		541
Accounts payable	483		716
Taxes accrued	158		161
Interest accrued	117		124
Non-trading derivative liabilities	11		19
Other	343		383
Total current liabilities	2,467		2,792
Other Liabilities:
Deferred income taxes, net	5,047		5,440
Non-trading derivative liabilities	5		1
Benefit obligations	904		953
Regulatory liabilities	1,276		1,206
Other	273		251
Total other liabilities	7,505		7,851
Long-term Debt:
VIE transition and system restoration bonds	2,283		2,674
Other long-term debt	5,618		5,335
Total long-term debt	7,901		8,009
Commitments and Contingencies (Note 14)
Shareholders’ Equity	3,461		4,548
Total Liabilities and Shareholders’ Equity	$	21,334	$	23,200



	Outstanding and Non-Vested Shares
	Year Ended December 31, 2015
	Shares (Thousands)		Weighted-Average Grant Date Fair Value		Remaining Average Contractual Life (Years)	Aggregate Intrinsic Value (Millions)
Outstanding as of December 31, 2014	2,460		$	21.26
Granted	1,158		21.28
Forfeited or canceled	(592	)	19.89
Vested and released to participants	(398	)	18.79
Outstanding as of December 31, 2015	2,628		21.95		1.2	$	28



	1% Increase		1% Decrease
	(in millions)
Effect on the postretirement benefit obligation	$	12	$	10
Effect on total of service and interest cost	1		1



	Fair Value Measurements as of December 31, 2015
	Total		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(in millions)
Mutual funds (1)	$	136	$	136	$	—	$	—
Total	$	136	$	136	$	—	$	—



			Postretirement Benefit Plan
	Pension Benefits		Benefit Payments		Medicare Subsidy Receipts
	(in millions)
2016	$	139	$	32	$	(4	)
2017	144		34		(4		)
2018	155		35		(5		)
2019	157		37		(6		)
2020	163		38		(6		)
2021-2025	822		203		(41		)



	Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Derivative assets and liabilities, net
	Year Ended December 31,
	2015			2014			2013
	(in millions)
Beginning balance	$	17		$	3		$	2
Total gains	7			14			3
Total settlements	(12		)	1			(3		)
Transfers out of Level 3	(1		)	—			—
Transfers into Level 3	1			(1		)	1
Ending balance (1)	$	12		$	17		$	3
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	$	6		$	16		$	2



	December 31, 2015				December 31, 2014
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)
Financial assets:
Notes receivable - affiliated companies	$	363	$	356	$	363	$	362
Financial liabilities:
Long-term debt	$	8,620	$	9,101	$	8,652	$	9,427



Column A	Column B		Column C					Column D		Column E
			Additions
	Balance at Beginning of Period		Charged to Income		Charged to Other Accounts			Deductions From Reserves (1)		Balance at End of Period
Description	(in millions)
Year Ended December 31, 2015
Accumulated provisions:
Uncollectible accounts receivable	$	26	$	19	$	(2	)	$	23	$	20
Deferred tax asset valuation allowance	2		—		—			—		2
Year Ended December 31, 2014
Accumulated provisions:
Uncollectible accounts receivable	$	28	$	22	$	2		$	26	$	26
Deferred tax asset valuation allowance	2		—		—			—		2
Year Ended December 31, 2013
Accumulated provisions:
Uncollectible accounts receivable	$	25	$	21	$	1		$	19	$	28
Deferred tax asset valuation allowance	2		—		—			—		2



Exhibit Number		Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference
2	—	Transaction Agreement dated July 21, 2004 among CenterPoint Energy, Utility Holding, LLC, NN Houston Sub, Inc., Texas Genco Holdings, Inc. (Texas Genco), HPC Merger Sub, Inc. and GC Power Acquisition LLC	CenterPoint Energy’s Form 8-K dated July 21, 2004	1-31447	10.1
3(a)	—	Restated Articles of Incorporation of CenterPoint Energy	CenterPoint Energy’s Form 8-K dated July 24, 2008	1-31447	3.2
†3(b)	—	Second Amended and Restated Bylaws of CenterPoint Energy
3(c)	—	Statement of Resolutions Deleting Shares Designated Series A Preferred Stock of CenterPoint Energy	CenterPoint Energy’s Form 10-K for the year ended December 31, 2011	1-31447	3(c)
4(a)	—	Form of CenterPoint Energy Stock Certificate	CenterPoint Energy’s Registration Statement on Form S-4	333-69502	4.1
4(c)	—	Contribution and Registration Agreement dated December 18, 2001 among Reliant Energy, CenterPoint Energy and the Northern Trust Company, trustee under the Reliant Energy, Incorporated Master Retirement Trust	CenterPoint Energy’s Form 10-K for the year ended December 31, 2001	1-31447	4.3
4(d)(1)	—	Mortgage and Deed of Trust, dated November 1, 1944 between Houston Lighting and Power Company (HL&P) and Chase Bank of Texas, National Association (formerly, South Texas Commercial National Bank of Houston), as Trustee, as amended and supplemented by 20 Supplemental Indentures thereto	HL&P’s Form S-7 filed on August 25, 1977	2-59748	2(b)
4(d)(2)	—	Twenty-First through Fiftieth Supplemental Indentures to Exhibit 4(d)(1)	HL&P’s Form 10-K for the year ended December 31, 1989	1-3187	4(a)(2)
4(d)(3)	—	Fifty-First Supplemental Indenture to Exhibit 4(d)(1) dated as of March 25, 1991	HL&P’s Form 10-Q for the quarter ended June 30, 1991	1-3187	4(a)
4(d)(4)	—	Fifty-Second through Fifty-Fifth Supplemental Indentures to Exhibit 4(d)(1) each dated as of March 1, 1992	HL&P’s Form 10-Q for the quarter ended March 31, 1992	1-3187	4
4(d)(5)	—	Fifty-Sixth and Fifty-Seventh Supplemental Indentures to Exhibit 4(d)(1) each dated as of October 1, 1992	HL&P’s Form 10-Q for the quarter ended September 30, 1992	1-3187	4



10(xx)	—	Amended and Restated Limited Liability Company Agreement of CNP OGE GP LLC dated as of May 1, 2013	CenterPoint Energy’s Form 8-K dated May 1, 2013	1-31447	10.2
10(yy)(1)	—	Second Amended and Restated Limited Liability Company Agreement of Enable GP, LLC dated as of July 30, 2013	CenterPoint Energy’s Form 10-Q for the quarter ended September 30, 2013	1-31447	10.2
10(yy)(2)	—	First Amendment to the Second Amended and Restated Limited Liability Company Agreement of Enable GP, LLC dated as of April 16, 2014	CenterPoint Energy’s Form 8-K dated April 16, 2014	1-31447	10.2
10(zz)	—	Registration Rights Agreement dated as of May 1, 2013 by and among 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
10(aaa)	—	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
10(bbb)	—	Agreement, dated June 26, 2013, by and between CERC Corp. and C. Gregory Harper	CenterPoint Energy’s Form 10-Q for the quarter ended June 30, 2013	1-31447	10.6
10(ccc)	—	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)
10(ddd)	—	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
10(eee)	—	Third Amended and Restated Agreement of Limited Partnership of Enable Midstream Partners, LP dated February 18, 2016	CenterPoint Energy’s Form 8-K dated February 18, 2016	1-31447	10.1
10(fff)	—	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
†12	—	Computation of Ratio of Earnings to Fixed Charges
†21	—	Subsidiaries of CenterPoint Energy
†23.1	—	Consent of Deloitte & Touche LLP
†23.2	—	Consent of Deloitte & Touche LLP, Independent Registered Public Accounting Firm of Enable Midstream Partners, LP
†31.1	—	Rule 13a-14(a)/15d-14(a) Certification of Scott M. Prochazka
†31.2	—	Rule 13a-14(a)/15d-14(a) Certification of William D. Rogers
†32.1	—	Section 1350 Certification of Scott M. Prochazka
†32.2	—	Section 1350 Certification of William D. Rogers
99.1	—	$1,400,000,000 Credit Agreement, dated as of May 1, 2013, among CEFS as Borrower, and the banks named therein	CenterPoint Energy’s Form 8-K dated May 1, 2013	1-31447	99.2
99.2	—	First Amendment and Waiver to Revolving Credit Agreement dated as of January 23, 2014 by and among Enable Midstream Partners, LP, the lenders party thereto and Citibank, N.A., as agent	CenterPoint Energy’s Form 10-K for the year ended December 31, 2013	1-31447	99.3
99.3	—	Financial Statements of Enable Midstream Partners, LP as of December 31, 2015 and 2014 and for the years ended December 31, 2015, 2014 and 2013	Part II, Item 8 of Enable Midstream Partners, LP’s Form 10-K for the year ended December 31, 2015	001-36413	Item 8
†101.INS	—	XBRL Instance Document
†101.SCH	—	XBRL Taxonomy Extension Schema Document
†101.CAL	—	XBRL Taxonomy Extension Calculation Linkbase Document
†101.DEF	—	XBRL Taxonomy Extension Definition Linkbase Document
†101.LAB	—	XBRL Taxonomy Extension Labels Linkbase Document

Recently Adopted Accounting Standards

ASU Number and Name

Description

Date of Adoption

Financial Statement Impact
upon Adoption

ASU 2018-14-Compensation-Retirement Benefits-Defined Benefit Plans-General (Subtopic 715-20): Disclosure Framework-Changes to the Disclosure Requirements for Defined Benefit Plans

This standard eliminates, modifies and adds certain disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans.
Transition method: retrospective

October 1, 2018

The adoption of this standard did not impact the Registrants’ financial position, results of operations, and cash flows. Note 8 reflects the disclosures modified upon adoption.