Document


 
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, 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              

 
Registrant, State or Other Jurisdiction
 of Incorporation or Organization
 
Commission file number
Address of Principal Executive Offices, Zip Code
 and Telephone Number
I.R.S. Employer Identification No.
 
 
 
1-31447
CenterPoint Energy, Inc.
74-0694415
 
(a Texas corporation)
 
 
1111 Louisiana
 
 
Houston, Texas 77002
 
 
(713-207-1111)
 
 
 
 
1-3187
CenterPoint Energy Houston Electric, LLC
22-3865106
 
(a Texas limited liability company)
 
 
1111 Louisiana
 
 
Houston, Texas 77002
 
 
(713-207-1111)
 
 
 
 
1-13265
CenterPoint Energy Resources Corp.
76-0511406
 
(a Delaware corporation)
 
 
1111 Louisiana
 
 
Houston, Texas 77002
 
 
(713-207-1111)
 
 
 
 
Securities registered pursuant to Section 12(b) of the Act:
Registrant
Title of each class
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
 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
CenterPoint Energy, Inc.
Yes þ
No o
CenterPoint Energy Houston Electric, LLC
Yes þ
No o
CenterPoint Energy Resources Corp.
Yes þ
No o






Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  
CenterPoint Energy, Inc.
Yes o
No þ
CenterPoint Energy Houston Electric, LLC
Yes o
No þ
CenterPoint Energy Resources Corp.
Yes o
No þ

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

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). 
CenterPoint Energy, Inc.
Yes þ
No o
CenterPoint Energy Houston Electric, LLC
Yes þ
No o
CenterPoint Energy Resources Corp.
Yes þ
No o

Indicate by check mark 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. 
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, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer”, “accelerated filer”, “smaller reporting company”, and “emerging growth company” in Rule 12b-2 of the Exchange Act.
 
Large accelerated filer
Accelerated filer
Non-accelerated filer
Smaller reporting company
Emerging growth company
CenterPoint Energy, Inc.
þ

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

The aggregate market values of the voting stock held by non-affiliates of the Registrants as of June 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 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 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 2019 Annual Meeting of Shareholders of CenterPoint Energy, which will be filed with the Securities and Exchange Commission within 120 days of December 31, 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
 
Item 1A.
 
Risk Factors
 
Item 1B.
 
Unresolved Staff Comments
 
Item 2.
 
Properties
 
Item 3.
 
Legal Proceedings
 
Item 4.
 
Mine Safety Disclosures
 
PART II
Item 5.
 
Market for Registrants’ Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
 
Item 6.
 
Selected Financial Data
 
Item 7.
 
Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
Item 7A.
 
Quantitative and Qualitative Disclosures About Market Risk
 
Item 8.
 
Financial Statements and Supplementary Data
 
Item 9.
 
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
 
Item 9A.
 
Controls and Procedures
 
Item 9B.
 
Other Information
 
PART III
Item 10.
 
Directors, Executive Officers and Corporate Governance
 
Item 11.
 
Executive Compensation
 
Item 12.
 
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
 
Item 13.
 
Certain Relationships and Related Transactions, and Director Independence
 
Item 14.
 
Principal Accounting Fees and Services
 
PART IV
Item 15.
 
Exhibits and Financial Statement Schedules
 
Item 16.
 
Form 10-K Summary
 
 

i



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

ii



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

iv



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

v



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

vi



 CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION


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

The Registrants have based their forward-looking statements on management’s beliefs and assumptions based on information reasonably available to management at the time the statements are made. The Registrants caution you that assumptions, beliefs, expectations, intentions and projections about future events may and often do vary materially from actual results. Therefore, the Registrants cannot assure you that actual results will not differ materially from those expressed or implied by the Registrants’ forward-looking statements. In this Form 10-K, unless context requires otherwise, the terms “our,” “we” and “us” are used as abbreviated references to CenterPoint Energy, Inc. together with its consolidated subsidiaries, including Houston Electric, 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 the Registrants’ forward-looking statements are described under “Risk Factors” in Item 1A and “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Certain Factors Affecting Future Earnings” and “ — Liquidity and Capital Resources — Other Matters — Other Factors That Could Affect Cash Requirements” in Item 7 of this report, which discussions are incorporated herein by reference.

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

vii



PART I

Item 1.
Business

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

The discussion of CenterPoint Energy’s consolidated financial information includes the financial results of Houston Electric and CERC, which, along with CenterPoint Energy, are collectively referred to as the Registrants. Where appropriate, information relating to a specific registrant has been segregated and labeled as such. Unless the context indicates otherwise, specific references to Houston Electric and CERC also pertain to CenterPoint Energy. In this Form 10-K, the terms “our,” “we” and “us” are used as abbreviated references to CenterPoint Energy, Inc. together with its consolidated subsidiaries, which, as of February 1, 2019, includes Vectren and its subsidiaries.

OUR BUSINESS

Overview

CenterPoint Energy is a public utility holding company and owns interests in Enable. As of December 31, 2018, CenterPoint Energy’s operating subsidiaries, Houston Electric and CERC Corp., owned and operated electric transmission and distribution and natural gas distribution facilities and supplied natural gas 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:
https://cdn.kscope.io/f060e148d811719d5165382df34f5ca5-cnpstructurechart1.jpg    
(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.


1



(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:


https://cdn.kscope.io/f060e148d811719d5165382df34f5ca5-usmapa15.jpg https://cdn.kscope.io/f060e148d811719d5165382df34f5ca5-usmaplegenda17.jpg
As of December 31, 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

For a discussion of operating income by segment, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Results of Operations by Reportable Segment” in Item 7 of Part II of this report. For additional information about the segments, see Note 19 to the consolidated financial statements. From time to time, we consider the acquisition or the disposition of assets or businesses.

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.


2



Following the Merger, CenterPoint Energy’s simplified corporate structure as of February 1, 2019 is shown below:https://cdn.kscope.io/f060e148d811719d5165382df34f5ca5-cnpstructurechart2colora01.jpg
The Registrants’ principal executive offices are located at 1111 Louisiana, Houston, Texas 77002 (telephone number: 713-207-1111).

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

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

our Ethics and Compliance Code;

our Corporate Governance Guidelines; and

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

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

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

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

3




Houston Electric’s distribution service territory as of December 31, 2018 is depicted below:
https://cdn.kscope.io/f060e148d811719d5165382df34f5ca5-electrica05.jpg
Electric Transmission
 
On behalf of REPs, Houston Electric delivers electricity from power plants to substations, from one substation to another and to retail electric customers taking power at or above 69 kV in locations throughout Houston Electric’s certificated service territory. Houston Electric constructs and maintains transmission facilities and provides transmission services under tariffs approved by the PUCT.

The ERCOT ISO is responsible for operating the bulk electric power supply system in the ERCOT market. Houston Electric’s transmission business, along with those of other owners of transmission facilities in Texas, supports the operation of the ERCOT ISO. Houston Electric participates with the ERCOT ISO and other ERCOT utilities to plan, design, obtain regulatory approval for and construct new transmission lines necessary to increase bulk power transfer capability and to remove existing constraints on the ERCOT transmission grid.
 
Electric Distribution
 
In ERCOT, end users purchase their electricity directly from certificated REPs. Houston Electric’s distribution network receives electricity from the transmission grid through power distribution substations and delivers electricity for REPs in its certificated service area by carrying lower-voltage power from the substation to the retail electric customer through distribution feeders. Houston Electric’s operations include construction and maintenance of distribution facilities, metering services, outage response services and call center operations. Houston Electric provides distribution services under tariffs approved by the PUCT. PUCT rules and market protocols govern the commercial operations of distribution companies and other market participants. Rates for these existing services are established pursuant to rate proceedings conducted before municipalities that have original jurisdiction and the PUCT.
 
Bond Companies

Houston Electric has special purpose subsidiaries consisting of the Bond Companies, which it consolidates. 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 Securitization Bonds, and conducting activities incidental thereto. The Securitization Bonds are repaid through charges imposed on customers in Houston Electric’s service territory.  For further discussion of the Securitization Bonds and the outstanding balances as of December 31, 2018 and 2017, see Note 14 to the consolidated financial statements.

Customers
 
Houston Electric serves nearly all of the Houston/Galveston metropolitan area. At December 31, 2018, Houston Electric’s customers consisted of approximately 65 REPs, which sell electricity to approximately 2.5 million metered customers in Houston

4



Electric’s certificated service area, and municipalities, electric cooperatives and other distribution companies located outside Houston Electric’s certificated service area. Each REP is licensed by, and must meet minimum creditworthiness criteria established by, the PUCT. Houston Electric does not have long-term contracts with any of its customers. It operates using a continuous billing cycle, with meter readings being conducted and invoices being distributed to REPs each business day. For information regarding Houston Electric’s major customers, see Note 19 to the consolidated financial statements. The table below reflects the number of metered customers in Houston Electric’s service area as of December 31, 2018:
 
Residential
 
Commercial/
Industrial
 
Total Customers
Texas Gulf Coast
2,198,225

 
287,145

 
2,485,370


Utility Technology

Houston Electric’s Smart Grid is comprised of the AMS, IG, ADMS and private telecommunications network. Since 2009, Houston Electric has deployed fully operational advanced meters to 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 reliability and restoration, enhance the consumer experience, support the growth of renewable energy and help the environment by reducing carbon emissions.

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

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

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Electric Lines - Transmission and Distribution. As of December 31, 2018, Houston Electric owned and operated the following electric transmission and distribution lines:
 
 
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, 2018, Houston Electric owned 235 major substation sites having a total installed rated transformer capacity of 68,338 megavolt amperes.
 
Service Centers.  As of December 31, 2018, Houston Electric operated 15 regional service centers located on a total of 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
 
Houston Electric holds non-exclusive franchises from certain incorporated municipalities in its service territory. In exchange for the payment of fees, these franchises give Houston Electric the right to use the streets and public rights-of-way of these municipalities to construct, operate and maintain its transmission and distribution system and to use that system to conduct its electric delivery business and for other purposes that the franchises permit. The terms of the franchises, with various expiration dates, typically range from 20 to 40 years.
 
Natural Gas Distribution (CenterPoint Energy and CERC)

CERC’s NGD engages in regulated intrastate natural gas sales to, and natural gas transportation and storage for, approximately 3.5 million residential, commercial, industrial and transportation customers in Arkansas, Louisiana, Minnesota, Mississippi, 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. CERC’s NGD also provides unregulated services in Minnesota consisting of residential appliance repair and maintenance services along with HVAC equipment sales.

CERC’s NGD’s service territory as of December 31, 2018 is depicted below:
https://cdn.kscope.io/f060e148d811719d5165382df34f5ca5-ngdterritorya11.jpghttps://cdn.kscope.io/f060e148d811719d5165382df34f5ca5-ngddescriptiona10.jpg

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Customers

In 2018, approximately 40% of CERC’s NGD’s total throughput was to residential customers and 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 natural gas sales to residential customers and natural gas sales and transportation for commercial and industrial customers is seasonal. In 2018, approximately 68% of CERC’s NGD’s total throughput occurred in the first and fourth quarters. These patterns reflect the higher demand for natural gas for heating purposes during the colder months.
 
Supply and Transportation.  In 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 2018 included 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 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 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 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.
 

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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. CERC’s NGD may also supplement contracted supplies and storage from time to time with stored LNG and propane-air plant production.
 
CERC’s NGD owns and operates an underground natural gas storage facility with a capacity of 7.0 Bcf. It has a working capacity of 2.0 Bcf available for use during the heating season and a maximum daily withdrawal rate of 50 MMcf. It also owns eight propane-air plants with a total production rate of 180,000 Dth per day and on-site storage facilities for 12 million gallons of propane (1.0 Bcf natural gas equivalent). It owns a LNG plant facility with a 12 million-gallon LNG storage tank (1.0 Bcf natural gas equivalent) and a production rate of 72,000 Dth per day.
 
On an ongoing basis, 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 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, 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 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 AMAs. CERC’s NGD has an obligation to purchase its winter storage requirements that have been released to the asset manager under these AMAs.

Assets
 
As of December 31, 2018, CERC’s NGD owned approximately 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 CES and its subsidiary, CEIP, collectively, Energy Services.
In 2018, CES marketed approximately 1,355 Bcf of natural gas (including approximately 33 Bcf to affiliates) and provided related energy services and transportation to approximately 30,000 customers in over 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.

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Energy Services’ service territory as of December 31, 2018 is depicted below:
https://cdn.kscope.io/f060e148d811719d5165382df34f5ca5-cesonlycombinedcolor01.jpg
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 risk management needs. These services include (1) through CEIP, permanent pipeline connections through interconnects with various interstate and intrastate pipeline companies and (2) through MES, temporary delivery of LNG and CNG throughout the lower 48 states, utilizing a fleet of customized equipment to provide continuity of natural gas service when pipeline supply is not available.

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

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

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with its supply portfolio in a manner that minimizes its total cost of supply. Should CES exceed this VaR limit, management is required to notify CenterPoint Energy’s Board of Directors.

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

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

Midstream Investments (CenterPoint Energy)

CenterPoint Energy’s Midstream Investments reportable segment consists of its equity method investment in Enable. Enable is a publicly traded MLP, jointly controlled by CenterPoint Energy (indirectly through CNP Midstream) and OGE as of December 31, 2018. 

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

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

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

Enable’s gathering and processing systems compete with gatherers and processors of all types and sizes, including those affiliated with various producers, other major pipeline companies and various independent midstream entities. In the process of selling NGLs, Enable competes against other natural gas processors extracting and selling NGLs. Enable’s primary competitors are other midstream companies who are active in the regions where it operates. Enable’s management views the principal elements of competition for its gathering and processing systems as gathering rate, processing value, system reliability, fuel rate, system run time, construction cycle time and prices at the wellhead.

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

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

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


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Other Operations (CenterPoint Energy and CERC)

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

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:

https://cdn.kscope.io/f060e148d811719d5165382df34f5ca5-vectrenutilityterritorya01.jpg
 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 further discussion of the Merger, see Note 4 to the consolidated financial statements.

REGULATION

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

Federal Energy Regulatory Commission

The FERC has jurisdiction under the NGA and the NGPA, as amended, to regulate the transportation of natural gas in interstate commerce and natural gas sales for resale in interstate commerce that are not first sales. The FERC regulates, among other things, the construction of pipeline and related facilities used in the transportation and storage of natural gas in interstate commerce, including the extension, expansion or abandonment of these facilities. The FERC has authority to prohibit market manipulation in connection with FERC-regulated transactions, to conduct audits and investigations, and to impose significant civil penalties (up to approximately $1.27 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. CenterPoint Energy’s and CERC’s Energy Services reportable segment markets natural gas in interstate commerce pursuant to blanket authority granted by the FERC.

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

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to ensuring the reliability of electric transmission service, including transmission facilities owned by Houston Electric and other utilities within ERCOT. The FERC has designated the NERC as the ERO to promulgate standards, under FERC oversight, for all owners, operators and users of the bulk power system (Electric Entities). The ERO and the FERC have authority to (a) impose fines and other sanctions on Electric Entities that fail to comply with approved standards and (b) audit compliance with approved standards. The FERC has approved the delegation by the NERC of authority for reliability in ERCOT to the Texas RE. 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 Houston Electric is required to make additional expenditures to comply with these standards, it is anticipated that 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, CenterPoint Energy and its consolidated subsidiaries are subject to reporting and accounting requirements and are required to maintain certain books and records and make them available for review by the FERC and state regulatory authorities in certain circumstances.

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

Houston Electric conducts its operations pursuant to a certificate of convenience and necessity issued by the PUCT that covers its present service area and facilities. The PUCT and certain municipalities have the authority to set the rates and terms of service provided by Houston Electric under cost-of-service rate regulation. Houston Electric holds non-exclusive franchises from certain incorporated municipalities in its service territory. In exchange for payment of fees, these franchises give Houston Electric the right to use the streets and public rights-of-way of these municipalities to construct, operate and maintain its transmission and distribution system and to use that system to conduct its electric delivery business and for other purposes that the franchises permit. The terms of the franchises, with various expiration dates, typically range from 20 to 40 years.

Houston Electric’s distribution rates charged to REPs for residential and small commercial customers are primarily based on amounts of energy delivered, whereas distribution rates for a majority of large commercial and industrial customers are primarily based on peak demand. All REPs in Houston Electric’s service area pay the same rates and other charges for transmission and distribution services. This regulated delivery charge includes the transmission and distribution rate (which includes municipal franchise fees), a distribution recovery mechanism for recovery of incremental distribution-invested capital above that which is already reflected in the base distribution rate, a nuclear decommissioning charge associated with decommissioning the South Texas nuclear generating facility, an EECR charge, and charges associated with securitization of regulatory assets, stranded costs and restoration costs relating to Hurricane Ike. Transmission rates charged to distribution companies are based on amounts of energy transmitted under “postage stamp” rates that do not vary with the distance the energy is being transmitted. All distribution companies in ERCOT pay Houston Electric the same rates and other charges for transmission services.

For a discussion of certain of 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” 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, NGD operates under franchises, certificates or licenses obtained from state and local authorities. The original terms of the franchises, with various expiration dates, typically range from 10 to 30 years, although franchises in Arkansas are perpetual. NGD expects to be able to renew expiring franchises. In most cases, franchises to provide natural gas utility services are not exclusive.

Substantially all of NGD is subject to cost-of-service rate regulation by the relevant state public utility commissions and, in Texas, by the Railroad Commission and those municipalities served by NGD that have retained original jurisdiction. In certain of its jurisdictions, NGD has 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” in Item 7 of Part II of this report, which discussion is incorporated herein by reference.


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

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

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

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

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

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

Interstate Natural Gas Pipeline Regulation

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

Market Behavior Rules; Posting and Reporting Requirements

The EPAct of 2005 amended the NGA to add an anti-manipulation provision that makes it unlawful for any entity to engage in prohibited behavior as prescribed in FERC rules, which were subsequently issued in FERC Order No. 670. The EPAct of 2005 also amends the NGA and the NGPA to give the FERC authority to impose civil penalties for violations of these statutes and FERC’s regulations, rules, and orders, of up to approximately $1.27 million per day per violation, subject to periodic adjustment to account for inflation. Should Enable fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, it could be subject to substantial penalties and fines. In addition, the CFTC is directed under the CEA to prevent price manipulations

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for the commodity and futures markets, including the energy futures markets. Pursuant to the Dodd-Frank Act and other authority, the CFTC has adopted anti-market manipulation regulations that prohibit fraud and price manipulation in the commodity and futures markets. The CFTC also has statutory authority to seek civil penalties of up to the greater of $1.2 million or triple the monetary gain to the violator for violations of the anti-market manipulation sections of the CEA. These maximum penalty levels are also subject to periodic adjustment to account for inflation.

Intrastate Natural Gas Pipeline and Storage Regulation

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

Natural Gas Gathering and Processing Regulation

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

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

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

Interstate Crude Oil Gathering Regulation

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

Intrastate Crude Oil and Condensate Gathering Regulation

Enable’s crude oil and condensate gathering system in the Anadarko Basin is located in Oklahoma and is subject to limited regulation by the OCC. Crude oil and condensate gathering systems are common carriers under Oklahoma law and are prohibited from unjust or unlawful discrimination in favor of one customer over another. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. Enable’s crude oil and condensate gathering operations could be adversely affected should they be subject in the future to the application of state or federal regulation of rates and services.


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Safety and Health Regulation

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

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

ENVIRONMENTAL MATTERS

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, the Registrants must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact the Registrants’ business activities in many ways, including, but not limited to:

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

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

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

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

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

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

construct or acquire new facilities and equipment;

acquire permits for facility operations;

modify, upgrade or replace existing and proposed equipment; and

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

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

The recent trend in environmental regulation has been to place more restrictions and limitations on activities that may impact the environment. There can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation and monitoring, and actual future expenditures may be different from the amounts currently anticipated. The

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Registrants try to anticipate future regulatory requirements that might be imposed and plan accordingly to maintain compliance with changing environmental laws and regulations.

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

Global Climate Change

There is increasing attention being paid in the United States and worldwide to the issue of climate change. As a result, from time to time, regulatory agencies have considered the modification of existing laws or regulations or the adoption of new laws or regulations addressing the emissions of GHG on the state, federal, or international level. Some of the proposals would require industrial sources to meet stringent new standards that would require substantial reductions in GHG emissions. CenterPoint Energy’s and CERC’s revenues, operating costs and capital requirements could be adversely affected as a result of any regulatory action that would require installation of new control technologies or a modification of their operations or would have the effect of reducing the consumption of natural gas. Houston Electric, in contrast to some electric utilities, does not generate electricity and thus is not directly exposed to the risk of high capital costs and regulatory uncertainties that face electric utilities that burn fossil fuels to generate electricity.  Nevertheless, CenterPoint Energy’s and Houston Electric’s revenues could be adversely affected to the extent any resulting regulatory action has the effect of reducing consumption of electricity by ultimate consumers within Houston Electric’s service territory. Likewise, incentives to conserve energy or to use energy sources other than natural gas could result in a decrease in demand for the Registrants’ services.  Conversely, regulatory actions that effectively promote the consumption of natural gas because of its lower emissions characteristics would be expected to beneficially affect CenterPoint Energy and CERC and their natural gas-related businesses.  At this point in time, however, it would be speculative to try to quantify the magnitude of the impacts from possible new regulatory actions related to GHG emissions, either positive or negative, on the Registrants’ businesses.

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

Air Emissions

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

The EPA has established new air emission control requirements for natural gas and NGLs production, processing and transportation activities. Under the NESHAPS, the EPA established the RICE MACT rule. Compressors and back up electrical

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generators used by CenterPoint Energy’s and CERC’s NGD, and back up electrical generators used by CenterPoint Energy and Houston Electric, are substantially compliant with these laws and regulations.

Water Discharges

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

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

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

Liability for Remediation

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

Liability for Preexisting Conditions

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


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EMPLOYEES

The following table sets forth the number of employees by Registrant and reportable segment as of December 31, 2018:
 
 
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
 
2,800

 
2,800

 

 
1,431

 
1,431

 

Natural Gas Distribution
 
3,298

 

 
3,298

 
1,200

 

 
1,200

Energy Services
 
302

 

 
302

 

 

 

Other Operations
 
1,577

 

 

 
127

 

 

Total
 
7,977

 
2,800

 
3,600

 
2,758

 
1,431

 
1,200


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

EXECUTIVE OFFICERS
(as of February 12, 2019)
Name
 
Age
 
Title
Milton Carroll
 
68
 
Executive Chairman
Scott M. Prochazka
 
52
 
President and Chief Executive Officer and Director
William D. Rogers
 
58
 
Executive Vice President and Chief Financial Officer
Tracy B. Bridge
 
60
 
Executive Vice President and President, Electric Division
Scott E. Doyle
 
47
 
Senior Vice President, Natural Gas Distribution
Joseph J. Vortherms
 
58
 
Senior Vice President, Energy Services
Dana C. O’Brien
 
51
 
Senior Vice President and General Counsel
Sue B. Ortenstone
 
62
 
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. He has served as a director of Health Care Service Corporation since 1998 and as its chairman since 2002. He previously served as a director of LyondellBasell Industries N.V. from July 2010 to July 2016 as well as LRE GP, LLC, the general partner of LRR Energy, L.P., from November 2011 to January 2014.

Scott M. Prochazka has served as a Director and President and Chief Executive Officer 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 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 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, United Way of Houston, Junior Achievement of South 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 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

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

Tracy B. Bridge 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 as the Chair of the Board of Directors of Rebuilding Together Houston.

Scott E. Doyle has served as Senior Vice President, Natural Gas Distribution since March 2017. With more than 20 years of utility experience, he previously served as Senior Vice President, Regulatory and Public Affairs from February 2014 to March 2017; as Division Vice President, Rates and Regulatory from April 2012 to February 2014; and as Division Vice President, Regional Operations from March 2010 to April 2012. Mr. Doyle currently serves on the 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, Energy Services since March 2017. He previously served as Vice President, Energy Services from November 2015 to March 2017; as Vice President, Regional Operations in Minnesota from October 2014 to November 2015; as Division Vice President, Regional Operations from April 2012 to October 2014; and as Director, Home Service Plus from January 2007 to April 2012. Mr. Vortherms currently serves on the Southern Gas Association Executive Council as well as the American Gas Association Scenario Planning Council. He previously served on the boards of the Minnesota Region American Red Cross and the Minnesota Business Partnership.

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

Item 1A.
Risk Factors

CenterPoint Energy is a holding company that conducts all of its business operations through subsidiaries, primarily Houston Electric, CERC and, as of February 1, 2019, Vectren through its operating subsidiaries. CenterPoint Energy also owns interests in Enable. The following, along with any additional legal proceedings identified or incorporated by reference in Item 3 of this combined report on Form 10-K, summarizes the principal risk factors associated with the holding company, the businesses conducted by its subsidiaries, including Vectren, and its interests in Enable. However, additional risks and uncertainties either not presently known or not currently believed by management to be material may also adversely affect CenterPoint Energy’s businesses. 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.


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Risk Factors Associated with Our Consolidated Financial Condition

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

CenterPoint Energy derives all of its operating income from, and holds all of its assets through, its subsidiaries, including its interests in Enable. As a result, CenterPoint Energy depends on distributions from its subsidiaries and Enable to meet its payment obligations and to pay dividends on its common and preferred stock. In general, CenterPoint Energy’s subsidiaries are separate and distinct legal entities and have no obligation to provide it with funds for its payment obligations, whether by dividends, distributions, loans or otherwise. In addition, provisions of applicable law, such as those limiting the legal sources of dividends, limit CenterPoint Energy’s subsidiaries’ and Enable’s ability to make payments or other distributions to CenterPoint Energy, and its subsidiaries or Enable could agree to contractual restrictions on their ability to make 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 CenterPoint Energy receives with respect to its interests in Enable, please read “— Additional Risk Factors Affecting CenterPoint Energy’s Interests in Enable Midstream Partners, LP — CenterPoint Energy’s cash flows will be adversely impacted if it receives less cash distributions from Enable than it currently expects.”

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

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

Our businesses are capital intensive, and we rely on various sources to finance our capital expenditures. For example, we depend on (i) long-term debt, (ii) borrowings through our revolving credit facilities and, for CenterPoint Energy and CERC, commercial paper programs, (iii) distributions from CenterPoint Energy’s interests in Enable (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, 2018, CenterPoint Energy had $9.2 billion of outstanding indebtedness on a consolidated basis, which includes $1.4 billion of non-recourse Securitization Bonds. For information on maturities through 2023, see Note 14 to the consolidated financial statements. 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. Our future financing activities may be significantly affected by, among other things:

general economic and capital market conditions;

credit availability from financial institutions and other lenders;

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

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

the future performance of our and Enable’s businesses;

integration of Vectren’s businesses into CenterPoint Energy;

maintenance of acceptable credit ratings;

market expectations regarding our future earnings and cash flows;

our ability to access capital markets on reasonable terms;

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

provisions of relevant tax and securities laws.

As of December 31, 2018, Houston Electric had approximately $3.3 billion aggregate principal amount of general mortgage bonds outstanding under the General Mortgage, including approximately $68 million held in trust to secure pollution control bonds for which CenterPoint Energy is obligated. Additionally, as of December 31, 2018, Houston Electric had approximately $102 million aggregate principal amount of first mortgage bonds outstanding under the Mortgage. Houston Electric may issue additional general mortgage bonds on the basis of retired bonds, up to 70% of property additions or cash deposited with the trustee. As of December 31, 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, 2018. However, 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.

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. On 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 their securities. Each rating should be evaluated independently of any other rating. Any future reduction or withdrawal of one or more of the Registrants’ credit ratings could have a material adverse impact on their ability to access capital on acceptable terms.

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

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

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

For investments CenterPoint Energy accounts for as investments without a readily determinable fair value, such as the Enable Series A Preferred Unit investment, the carrying value of the asset may be adjusted to fair value, resulting in a gain or loss in the

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period, if a transaction on an identical or similar investment in Enable is observed. Additionally, CenterPoint Energy considers qualitative impairment triggers, such as significant deterioration in earnings performance, significant decline in market condition and other factors that raise significant concerns about Enable’s ability to continue as a going concern, to determine if an impairment analysis should be performed on its investment.

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

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

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

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 the Registrants or Enable could result in financial losses that could negatively impact the Registrants’ results of operations and those of Enable.

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

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

CenterPoint Energy has approximately $828 million principal amount of ZENS outstanding as of December 31, 2018. CenterPoint Energy owns shares of ZENS-Related Securities equal to approximately 100% of the reference shares used to calculate

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

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

Houston Electric’s rates are regulated by certain municipalities and the PUCT and Indiana Electric’s rates are regulated by the IURC. Their rates are set in comprehensive base rate proceedings (i.e., general rate cases) based on an analysis of their invested capital, their expenses and other factors in a designated test year. Each of these rate proceedings is subject to third-party intervention and appeal, and the timing of a general base rate proceeding may be out of Houston Electric’s and Indiana Electric’s control. For Houston Electric, a general base rate proceeding is required 48 months from the date of the 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 the general 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 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

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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 Houston Electric’s sales of transmission and distribution services.

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

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

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

A significant portion of Indiana Electric’s sales are for space heating and cooling. Consequently, Indiana Electric’s results of operations may be adversely affected by warmer-than-normal heating season weather or colder-than-normal cooling season weather, while more extreme seasonal weather conditions could increase Indiana Electric’s results of operations in a manner that would not likely be annually recurring.

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

Houston Electric and Indiana Electric are members of ERCOT and MISO, respectively, which serve the electric transmission needs of their applicable regions. As a result of their respective participation in ERCOT and MISO, Houston Electric and Indiana Electric do not have operational control over their transmission facilities and are subject to certain costs for improvements to these regional electric transmission systems. In addition, the FERC has jurisdiction with respect to ensuring the reliability of electric transmission service, including transmission facilities owned by Houston Electric and other utilities within ERCOT and Indiana Electric and other utilities within MISO, respectively. The FERC has designated the NERC as the ERO to promulgate standards, under FERC oversight, for all owners, operators and users of the bulk power system. The FERC has approved the delegation by the NERC of authority for reliability in ERCOT to the Texas RE, a Texas non-profit corporation and for reliability in the portion of MISO that includes Indiana Electric to ReliabilityFirst Corporation, a Delaware non-profit corporation. Compliance with mandatory reliability standards may subject Houston Electric and Indiana Electric to higher operating costs and may result in increased capital expenditures. In addition, if Houston Electric or Indiana Electric were to be found to be in noncompliance with applicable mandatory reliability standards, they could be subject to sanctions, including substantial monetary penalties.

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

Houston Electric’s receivables from the distribution of electricity are collected from REPs that supply the electricity Houston Electric distributes to their customers. As of December 31, 2018, Houston Electric did business with approximately 65 REPs. Adverse economic conditions, structural problems in the market served by ERCOT or financial difficulties of one or more REPs could impair the ability of these REPs to pay for Houston Electric’s services or could cause them to delay such payments. Houston Electric depends on these REPs to remit payments on a timely basis. Applicable regulatory provisions require that customers be shifted to another REP or a provider of last resort if a REP cannot make timely payments. Applicable PUCT regulations significantly limit the extent to which Houston Electric can apply normal commercial terms or otherwise seek credit protection from firms desiring to provide retail electric service in its service territory, and Houston Electric thus remains at risk for payments related to services provided prior to the shift to another REP or the provider of last resort. A significant portion of Houston Electric’s billed receivables from REPs are from affiliates of NRG and Vistra Energy Corp., formerly known as TCEH Corp. Houston Electric’s aggregate billed receivables balance from REPs as of December 31, 2018 was $207 million. Approximately 34% and 12% of this amount was owed by affiliates of NRG and Vistra Energy Corp., respectively. Any delay or default in payment by REPs could adversely affect Houston Electric’s cash flows, financial condition and results of operations. If a REP were unable to meet its obligations, it could consider, among various options, restructuring under the bankruptcy laws, in which event such REP might seek to avoid honoring its obligations, and claims might be made by creditors involving payments Houston Electric had received from such REP.

The AMS deployed throughout Houston Electric’s 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.


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

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

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

Though several interim rate adjustment mechanisms have been approved by jurisdictional regulatory authorities and implemented by NGD to reduce the effects of regulatory lag, such adjustment mechanisms are subject to the applicable regulatory body’s approval 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 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

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produce recovery of NGD’s costs or enable NGD to earn an expected return. In addition, changes to the interim adjustment mechanisms could result in an increase in regulatory lag or otherwise impact NGD’s ability to recover its costs in a timely manner. Additionally, inherent in the regulatory process is some level of risk that jurisdictional regulatory authorities may initiate investigations of the prudence of operating expenses incurred or capital investments made by NGD and deny the full recovery of NGD’s cost of service or the full recovery of incurred natural gas costs in rates. To the extent the regulatory process does not allow NGD to make a full and timely recovery of appropriate costs, its results of operations, financial condition and cash flows could be adversely affected.

Unlike CERC, Indiana Gas, SIGECO’s natural gas distribution business and VEDO must seek approval by the IURC and PUCO, as applicable, for long-term financing authority. This authority allows these utilities the flexibility to 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 their suppliers and customers to meet their obligations or otherwise adversely affect their liquidity, results of operations and financial condition.

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

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

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

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

NGD’s and CES’s revenues are primarily derived from natural gas sales. Thus, their revenues and results of operations are subject to seasonality, weather conditions and other changes in natural gas usage, with revenues being higher during the winter

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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 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 NGD’s ability to operate.

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

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

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

NGD and CES compete primarily with alternate energy sources such as electricity and other fuel sources. In some areas, intrastate pipelines, other natural gas distributors and marketers also compete directly with NGD and CES for natural gas sales to end users. In addition, as a result of federal regulatory changes affecting interstate pipelines, natural gas marketers operating on these pipelines may be able to bypass NGD’s facilities and market, sell and/or transport natural gas directly to commercial and industrial customers. Any reduction in the amount of natural gas marketed, sold or transported by NGD and CES as a result of competition may have an adverse impact on our results of operations, financial condition and cash flows.

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

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

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

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

CenterPoint Energy holds a substantial limited partner interest in Enable (54.0% of the outstanding common units representing limited partner interests in Enable as of December 31, 2018), as well as 50% of the management rights in Enable GP and a 40% interest in the incentive distribution rights held by Enable GP. As of December 31, 2018, CenterPoint Energy owned an aggregate of 14,520,000 Enable Series A Preferred Units representing limited partner interests in Enable. Accordingly, CenterPoint Energy’s future earnings, results of operations, cash flows and financial condition will be affected by the performance of Enable, the amount of cash distributions it receives from Enable and the value of its interests in Enable. Factors that may have a material impact on Enable’s performance and cash distributions, and, hence, the value of CenterPoint Energy’s interests in Enable, include the risk factors outlined below, as well as the risks described elsewhere under “Risk Factors” that are applicable to Enable.

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

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

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

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

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

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

cash calls and settlements of hedging positions;

margin requirements on open price risk management assets and liabilities;

the level of competition from other companies offering midstream services;

adverse effects of governmental and environmental regulation;

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

prevailing economic conditions.

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

the level and timing of its capital expenditures;

the cost of acquisitions;

its debt service requirements and other liabilities;

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fluctuations in its working capital needs;

its ability to borrow funds and access capital markets;

restrictions contained in its debt agreements;

the amount of cash reserves established by Enable GP;

distributions paid on the Enable Series A Preferred Units;

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

other business risks affecting its cash levels.

Additionally, 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 and the Enable Series A Preferred Units depends primarily on its cash flow rather than on its profitability, which may prevent Enable from making distributions, even during periods in which Enable records net income.

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

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

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

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

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

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

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

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

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

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

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

Customers: Enable depends on a small number of customers for a significant portion of its gathering and processing revenues and its transportation and storage revenues. The loss of, or reduction in volumes from, these customers or the failure to extend or replace these contracts or the extension or replacement of these contracts on less favorable terms, as a result of competition or otherwise, could result in a decline in sales of its gathering and processing or transportation and storage services and adversely affect Enable’s financial position, results of operations and ability to make cash distributions;

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

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

Cost Recovery of Capital Improvements: Enable may not be able to recover the costs of its substantial planned investment in capital improvements and additions, and the actual cost of such improvements and additions may be significantly higher than it anticipates. In Enable’s Form 10-K for the fiscal year ended December 31, 2018, Enable stated that it expects that its expansion capital could range from approximately $325 million to $425 million and its maintenance capital could range from approximately $105 million to $125 million for the year ending December 31, 2019;

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

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

“Negotiated Rate” Contracts: Enable provides certain transportation and storage services under fixed-price “negotiated rate” contracts, which are authorized by the FERC, that are not subject to adjustment, even if its cost to perform these services exceeds the revenues received from these contracts. As of December 31, 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 “negotiated rate” contracts. As a result, Enable’s costs could exceed its revenues received under these contracts, and if Enable’s costs increase and it is not able to recover any shortfall of revenue associated with its negotiated rate contracts, the cash flow realized by its systems could decrease and, therefore, the cash Enable has available for distribution could also decrease;

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

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

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

Enable conducts a portion of its operations through joint ventures with third parties, including Enbridge Inc., DCP Midstream, LP, CVR 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.

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

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

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


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

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

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

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

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

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

Enable owns a 50% ownership interest in SESH. The remaining 50% ownership interest is held by Enbridge Inc. CenterPoint Energy owns 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 on acceptable terms.

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

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

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


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

As of December 31, 2018, Enable had approximately $2.9 billion of long-term debt outstanding, excluding the premiums, discounts and unamortized debt expense on their senior notes, $649 million outstanding under its commercial paper program and $500 million outstanding of 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, with approximately $250 million in borrowings outstanding and $848 million remaining available as of February 1, 2019. Enable has the ability to incur additional debt, subject to limitations in its credit facilities. The levels of Enable’s debt could have important consequences, including the following:

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

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

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

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

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

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

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

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

permit its subsidiaries to incur or guarantee additional debt;

incur or permit to exist certain liens on assets;

dispose of assets;

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

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

change the nature of its business.

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


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

Enable’s businesses are exposed to various regulatory risks.

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

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

FERC Revised Policy Statement and NOPR: In a series of related issuances on March 15, 2018, the FERC issued a Revised Policy Statement stating that it will no longer permit pipelines organized as MLPs to recover an income tax allowance in their cost-of-service rates. On July 18, 2018, FERC issued a Final Rule adopting procedures that are generally the same as proposed in a March 15, 2018 NOPR implementing the Revised Policy Statement and the corporate income tax rate reduction with certain clarifications and modifications. For more information, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Regulatory Matters” in Item 7 of Part II of this report, which discussion is incorporated herein by reference. If FERC requires Enable to establish new tariff rates for either its natural gas or crude oil pipelines that reflect a lower federal corporate income tax rate, it is possible the rates would be reduced, which could adversely affect Enable’s financial position, results of operations and ability to make cash distributions to its unitholders. With regard to FERC-jurisdictional rates on Enable’s crude oil pipelines, the FERC plans to address the Revised Policy Statement and corporate tax rate reduction in its next five-year review of the oil pipeline rate index, which will occur in 2020 and become effective July 1, 2021. The potential rate impacts from the revision are currently uncertain.

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

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

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


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

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

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

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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 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.

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

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

Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial actions, and the issuance of orders enjoining

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

In April 2015, the EPA finalized its CCR Rule, which regulates ash as 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 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, Houston Electric does not have insurance covering its transmission and distribution system, other than substations, because Houston Electric believes it to be cost prohibitive and believes insurance capacity to be limited. Historically, Houston Electric has been able to recover the costs incurred in restoring its transmission and distribution properties following hurricanes or other disasters through issuance of storm restoration bonds or a change in its regulated rates or otherwise. In the future, any such recovery may not be granted. Therefore, Houston Electric may not be able to restore any loss of, or damage to, any of its transmission and distribution properties without negative impact on its results of operations, financial condition and cash flows.

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.

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

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

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

38




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 they have transferred to others.

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

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

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

In connection with the organization and capitalization of RRI (now GenOn) and Texas Genco (now an affiliate of NRG), those companies and/or their subsidiaries assumed liabilities associated with various assets and businesses transferred to them and agreed to certain indemnity agreements of the Registrants. Such indemnities have applied in various asbestos and other environmental matters that arise from time to time and cases such as the litigation arising out of sales of natural gas in California and other markets (further appellate review of the 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 not approved by the federal district court, CES could incur liability and be responsible for satisfying 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 CenterPoint Energy would assume and agree to indemnify Texas Genco against, liabilities that Texas Genco originally assumed in connection with its organization to the extent, and only to the extent, that such liabilities are covered by certain insurance policies held by CenterPoint Energy, and in certain of the asbestos lawsuits CenterPoint Energy has agreed to continue to defend such claims to the extent they are covered by insurance maintained by CenterPoint Energy, subject to reimbursement of the costs of such defense by an NRG affiliate.

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

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

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

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

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


39



labor disputes;

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

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

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

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

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

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

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

Our and Enable’s businesses are dependent on recruiting, retaining and motivating employees. Certain circumstances, such as an aging workforce without appropriate replacements, a mismatch of existing skillsets to future needs, or the unavailability of contract resources may lead to operating challenges such as a lack of resources, loss of knowledge or a lengthy time period associated with skill development. Our and Enable’s costs, including costs to replace employees, productivity costs and safety costs, may rise. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to the new employees, or the future availability and cost of contract labor may adversely affect the ability to manage and operate our and Enable’s businesses. If we and Enable are unable to successfully attract and retain an appropriately qualified workforce, our and Enable’s results of operations could be negatively affected.

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

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

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.


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Following a finding by the EPA that certain GHGs represent an endangerment to human health, the EPA adopted two sets of rules regulating GHG emissions under the Clean Air Act, one that requires a reduction in emissions of GHGs from motor vehicles and another that regulates emissions of GHGs from certain large stationary sources. The EPA has also expanded its existing GHG emissions reporting requirements. These permitting and reporting requirements could lead to further regulation of GHGs by the EPA. As a distributor and transporter of natural gas, or a consumer of natural gas in its pipeline and gathering businesses, NGD’s or Enable’s revenues, operating costs and capital requirements, as applicable, could be adversely affected as a result of any regulatory action that would require installation of new control technologies or a modification of its operations or would have the effect of reducing the consumption of natural gas. 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 businesses’ revenues could be adversely affected to the extent any resulting regulatory action has the effect of reducing consumption of electricity by ultimate consumers within its service territory. Likewise, incentives to conserve energy or use energy sources other than natural gas could result in a decrease in demand for our services.

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.

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


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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.

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. We have several separate bargaining units, each with a unique collective bargaining agreement described below: 

The collective bargaining agreement with IBEW Local 66 related to employees of Houston Electric is scheduled to expire in May 2020;

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

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The collective bargaining agreements with Gas Workers Union Local 340, IBEW Local 949 and OPEIU Local 12 and Mankato related to NGD employees in Minnesota are scheduled to expire in April 2020, December 2020, May 2021 and March 2021, respectively;

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 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 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 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, fail to obtain access to important technologies or incur significant expenditures in adapting to technological change, or if implemented technology does not operate as anticipated, our businesses, operating results, financial condition and cash flows could be materially and adversely affected.

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

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

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

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

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

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

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

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

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

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

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

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 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 future material impairment charges to write-down the carrying value of certain assets, including goodwill, to their respective fair values.


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For example, Houston Electric’s business is largely concentrated in Houston, Texas, where a higher percentage of employment is tied to the energy sector relative to other regions of the country. Although Houston, Texas has a diverse economy, employment in the energy industry remains important with overall Houston employment growing at a moderate rate in 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 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, 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 the Electric Transmission & Distribution 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 the Natural Gas Distribution reportable segment, please read “Business — Our Business — Natural Gas Distribution — Assets” in Item 1 of this report, which information is incorporated herein by reference.

Energy Services (CenterPoint Energy and CERC)

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

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Midstream Investments (CenterPoint Energy)

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

Other Operations (CenterPoint Energy and CERC)

For information regarding the properties of the Other Operations 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 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 16(d) to the consolidated financial statements, which information is incorporated herein by reference.

Item 4.
Mine Safety Disclosures

Not applicable.

PART II

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

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

CenterPoint Energy

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

The amount of future cash dividends will be subject to determination based upon CenterPoint Energy’s results of operations and financial condition, future business prospects, any applicable contractual restrictions and other factors that CenterPoint Energy’s Board of Directors considers relevant and will be declared at the discretion of CenterPoint Energy’s Board of Directors. For further information on CenterPoint Energy’s dividends, see Note 13 to the consolidated financial statements.

Repurchases of Equity Securities

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

Houston Electric

As of February 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.


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Item 6.        Selected Financial Data (CenterPoint Energy)

The following table presents selected financial data with respect to CenterPoint Energy’s consolidated financial condition and consolidated results of operations and should be read in conjunction with CenterPoint Energy’s consolidated financial statements and the related notes in Item 8 of this report.
 
Year Ended December 31,
 
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)
Net income for the year ended December 31, 2017 includes a reduction in income tax expense of $1,113 million due to tax reform. See Note 15 to the consolidated financial statements for further discussion of the impacts of the TCJA implementation.

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

(3)
Amounts for 2014 and 2015 have been recast to reflect adoption of ASU 2015-03.
 
(4)
Total assets as of December 31, 2018 include cash and cash equivalents of $4.2 billion.

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

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

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

47




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

CenterPoint Energy, Inc. is a public utility holding 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 and natural gas distribution facilities and supply natural gas to commercial and industrial customers and electric and natural gas utilities.

Houston Electric engages in the electric transmission and distribution business in the Texas Gulf Coast area that includes the city of Houston; and

CERC Corp. (i) owns and operates natural gas distribution systems in six states and (ii) obtains and offers competitive variable and fixed-price physical natural gas supplies and services primarily to commercial and industrial customers and electric and natural gas utilities in over 30 states through its wholly-owned subsidiary, CES.

As of December 31, 2018, CenterPoint Energy, indirectly through CNP Midstream, owned approximately 54.0% of the common units representing limited partner interests in Enable, 50% of the management rights and 40% of the incentive distribution rights in Enable GP and also directly owned an aggregate of 14,520,000 Enable Series A Preferred Units. Enable owns, operates and develops natural gas and crude oil infrastructure assets.

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

Electric transmission and distribution services are subject to rate regulation and are reported in the Electric Transmission & Distribution 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 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 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 the Midstream Investments reportable segment are dependent upon the results of Enable, which are driven primarily by the volume of natural gas, NGLs and crude oil that Enable gathers, processes and transports across its systems and other factors as discussed below under “— Factors Influencing Midstream Investments.”

CenterPoint Energy’s Other Operations reportable segment includes office buildings and other real estate used for business operations, home repair protection plans through a third party and other corporate support operations that support

48



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

EXECUTIVE SUMMARY

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

Factors Influencing Our Businesses and Industry Trends

We are an energy delivery company. The majority of our revenues are generated from the transmission and delivery of electricity and the sale of natural gas by our subsidiaries, 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 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 our reportable segments, including the number of customers, throughput, use per customer, commodity prices and heating and cooling degree days. From an operational standpoint, we monitor safety factors, system reliability and customer satisfaction to gauge our performance.

The nature of our businesses requires significant amounts of capital investment, and we rely on internally generated cash, borrowings under our credit facilities, proceeds from commercial paper and issuances of debt and equity in the capital markets to satisfy these capital needs. We strive to maintain investment grade ratings for our securities to access the capital markets on terms we consider reasonable. A reduction in our ratings generally would increase our borrowing costs for new issuances of debt, as well as borrowing costs under our existing revolving credit facilities, and may prevent us from accessing the commercial paper markets. Disruptions in the financial markets can also affect the availability of new capital on terms we consider attractive. In those circumstances, we may not be able to obtain certain types of external financing or may be required to accept terms less favorable than they would otherwise accept. For that reason, we seek to maintain adequate liquidity for our businesses through existing credit facilities and prudent refinancing of existing debt.

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.

49




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 CERC’s business. In accordance with natural gas pipeline safety and integrity regulations, CERC is making, and will continue to make, significant capital investments in its service territories, which are necessary to help operate and maintain a safe, reliable and growing natural gas system. CERC’s compliance expenses may also increase as a result of preventative measures required under these regulations. Consequently, new rates in the areas it serves are necessary to recover these increasing costs.

Consistent with the regulatory treatment of pension costs, the Registrants defer the amount of pension expense that differs from the level of pension expense included in the Registrants’ base rates for the Electric Transmission & Distribution reportable segment and Natural Gas Distribution 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.

50




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

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

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

Enable’s long-term view is that natural gas and crude oil production in the U.S. will increase. Natural gas continues to be a critical component of energy demand in the 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 power plants by natural gas-fired power plants due to the price of natural gas and stricter government environmental regulations on the mining and burning of coal. Enable’s management believes that increasing consumption of natural gas over the long term in these sectors will continue to drive demand for Enable’s natural gas gathering, processing, transportation and storage services.

Significant Events

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

Credit Facility. On October 5, 2018, CenterPoint Energy terminated all remaining commitments by lenders to provide the Bridge Facility, which resulted in increased aggregate commitments under CenterPoint Energy’s revolving credit facility. For further information, see Note 14 to the consolidated financial statements.

Enable Midstream Spin. On September 4, 2018, CERC completed the Internal Spin of its equity investment in Enable and Enable GP. For further information regarding the Internal Spin, see Note 11 to the consolidated financial statements.


51



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. For further information about the equity offerings, see Note 13 to the consolidated financial statements.

Debt Transactions. In February 2018, Houston Electric issued $400 million aggregate principal amount of general mortgage bonds. In March 2018, CERC issued $600 million aggregate principal amount of unsecured senior notes. In October 2018, CenterPoint Energy issued $1.5 billion aggregate principal amount of senior notes. In January 2019, Houston Electric issued $700 million 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.

Regulatory Proceedings. For details related to pending and completed regulatory proceedings during 2018 and to date in 2019, see “—Liquidity and Capital Resources — Regulatory Matters” below.

CERTAIN FACTORS AFFECTING FUTURE EARNINGS

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

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

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

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

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

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

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

changes in tax status; and

access to debt and equity capital;

CenterPoint Energy’s expected benefits of the Merger and integration, including the outcome of shareholder litigation filed against Vectren that could reduce anticipated benefits of the Merger, as well as the ability to successfully integrate the Vectren businesses and realize anticipated benefits and the risk that the credit ratings of the combined company or its subsidiaries may be different from what CenterPoint Energy expects;

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;


52



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 investments;

our ability to control operation and maintenance costs;

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

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

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

changes in rates of inflation;

inability of various counterparties to meet their obligations to us;

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

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

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

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

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

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

the outcome of litigation;

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


53



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

CENTERPOINT ENERGY CONSOLIDATED RESULTS OF OPERATIONS
 
Year Ended December 31,
 
2018
 
2017
 
2016
 
(in millions, except per share amounts)
Revenues
$
10,589

 
$
9,614

 
$
7,528

Expenses
9,758

 
8,478

 
6,505

Operating Income
831

 
1,136

 
1,023

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
307

 
265

 
208

Other Income (Expense), net
50

 
(4
)
 
(29
)
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


2018 Compared to 2017

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

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

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

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

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


54



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

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

a $29 million increase in losses on marketable securities.

These decreases were partially offset by:

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

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

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

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

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

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

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

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

55




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
)