CenterPoint Energy, Inc.
CENTERPOINT ENERGY INC (Form: 10-K, Received: 02/28/2017 06:25:15)


 
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, 2016
OR
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
 
 
FOR THE TRANSITION PERIOD FROM                  TO               

Commission File Number 1-31447
______________________
CenterPoint Energy, Inc.
(Exact name of registrant as specified in its charter)
Texas
74-0694415
(State or other jurisdiction of incorporation or organization)
(I.R.S. Employer Identification No.)
 
 
1111 Louisiana
Houston, Texas 77002
(Address and zip code of principal executive offices)
(713) 207-1111
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Name of each exchange on which registered
Common Stock, $0.01 par value
New York Stock Exchange
Chicago 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.  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.  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.  Yes  þ  No  o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes  þ  No  o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K 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.  þ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
      Large accelerated filer  þ
Accelerated filer  o
Non-accelerated filer  o
Smaller reporting company  o
 
 
(Do not check if a smaller reporting company)
 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes  o  No  þ

The aggregate market value of the voting stock held by non-affiliates of CenterPoint Energy, Inc. (CenterPoint Energy) was $10,273,144,728 as of June 30, 2016 , using the definition of beneficial ownership contained in Rule 13d-3 promulgated pursuant to the Securities Exchange Act of 1934 and excluding shares held by directors and executive officers. As of February 10, 2017 , CenterPoint Energy had  430,688,867  shares of Common Stock outstanding. Excluded from the number of shares of Common Stock outstanding are 166 shares held by CenterPoint Energy as treasury stock.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the definitive proxy statement relating to the 2017 Annual Meeting of Shareholders of CenterPoint Energy, which will be filed with the Securities and Exchange Commission within 120 days of December 31, 2016 , 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
 
 

i



GLOSSARY
AEM
 
Atmos Energy Marketing, LLC, 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
AOL
 
AOL Inc.
APSC
 
Arkansas Public Service Commission
ArcLight
 
ArcLight Capital Partners, LLC
ARO
 
Asset retirement obligation
ASC
 
Accounting Standards Codification
ASU
 
Accounting Standards Update
AT&T
 
AT&T Inc.
AT&T Common
 
AT&T common stock
Btu
 
British thermal units
Bcf
 
Billion cubic feet
Bond Companies
 
Transition and system restoration bond companies
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
CEA
 
Commodities Exchange Act
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
 
Charter Communications, Inc.
Charter Common
 
Charter common stock
CIP
 
Conservation Improvement Program
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
DCRF
 
Distribution Cost Recovery Factor
DOE
 
U.S. Department of Energy
DOT
 
U.S. Department of Transportation
Dth
 
Dekatherms
EECR
 
Energy Efficiency Cost Recovery
EECRF
 
Energy Efficiency Cost Recovery Factor
EGT
 
Enable Gas Transmission, LLC
EIA
 
U.S. Energy Information Administration

Enable
 
Enable Midstream Partners, LP
Energy Future Holdings
 
Energy Future Holdings Corp.
EPA
 
Environmental Protection Agency
EPAct of 2005
 
Energy Policy Act of 2005
ERCOT
 
Electric Reliability Council of Texas
ERCOT ISO
 
ERCOT Independent System Operator

ii



GLOSSARY (cont.)
ERISA
 
Employee Retirement Income Security Act of 1974
ERO
 
Electric Reliability Organization
FASB
 
Financial Accounting Standards Board
FERC
 
Federal Energy Regulatory Commission
Fitch
 
Fitch, Inc.
FRP
 
Formula Rate Plan
GenOn
 
GenOn Energy, Inc.
GHG
 
Greenhouse gases
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
IRS
 
Internal Revenue Service
LIBOR
 
London Interbank Offered Rate
LNG
 
Liquefied natural gas
LPSC
 
Louisiana Public Service Commission
LTIPs
 
Long-term incentive plans
MGPs
 
Manufactured gas plants
MLP
 
Master Limited Partnership
MMBtu
 
One million British thermal units
MMcf
 
Million cubic feet
Moody’s
 
Moody’s Investors Service, Inc.
MPSC
 
Mississippi Public Service Commission
MPUC
 
Minnesota Public Utilities Commission
MRT
 
Enable-Mississippi River Transmission, LLC
NAV
 
Net asset value
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
NRG
 
NRG Energy, Inc.
NYSE
 
New York Stock Exchange
OCC
 
Oklahoma Corporation Commission
OGE
 
OGE Energy Corp.
PBRC
 
Performance Based Rate Change
PHMSA
 
Pipeline and Hazardous Materials Safety Administration
PRPs
 
Potentially responsible parties
PUCT
 
Public Utility Commission of Texas
Railroad Commission
 
Railroad Commission of Texas
RCRA
 
Resource Conservation and Recovery Act
REIT
 
Real Estate Investment Trust

iii



GLOSSARY (cont.)
Reliant Energy
 
Reliant Energy, Incorporated
REP
 
Retail electric provider
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 Units
 
Enable’s 10% Series A Fixed-to-Floating Non-Cumulative Redeemable Perpetual Preferred Units
Shell
 
Royal Dutch Shell plc
S&P
 
Standard & Poor’s Ratings Services, a division of The McGraw-Hill Companies
TCOS
 
Transmission Cost of Service
TDU
 
Transmission and distribution utility
Time Common
 
Time Inc. common stock
Transition Agreements
 
Services Agreement, Employee Transition Agreement, Transitional Seconding Agreement and other agreements entered into in connection with the formation of Enable
TRE
 
Texas Reliability Entity
TW
 
Time Warner Inc.
TW Common
 
TW common stock
TWC
 
Time Warner Cable Inc.
TWC Common
 
TWC common stock
TW Securities
 
Charter Common, Time Common and TW Common
VaR
 
Value at Risk
Verizon
 
Verizon Communications, Inc.
VIE
 
Variable interest entity
ZENS
 
2.0% Zero-Premium Exchangeable Subordinated Notes due 2029
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


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  CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

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

We have based our forward-looking statements on our management’s beliefs and assumptions based on information reasonably available to our management at the time the statements are made. We caution you that assumptions, beliefs, expectations, intentions and projections about future events may and often do vary materially from actual results. Therefore, we cannot assure you that actual results will not differ materially from those expressed or implied by our forward-looking statements.

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

v



PART I

Item 1.
Business

OUR BUSINESS

Overview

We are a public utility holding company. Our operating subsidiaries own and operate electric transmission and distribution and natural gas distribution facilities, supply natural gas to commercial and industrial customers and electric and natural gas utilities and own interests in Enable as described below. Our indirect, wholly-owned subsidiaries include:

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

CERC Corp., which owns and operates natural gas distribution systems in six states; and

CES, which 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 31 states.

As of December 31, 2016 , we also owned an aggregate of 14,520,000 Series A Preferred Units in Enable, which owns, operates and develops natural gas and crude oil infrastructure assets, and CERC Corp. owned approximately 54.1% of the limited partner interests in Enable.

Our reportable business segments are Electric Transmission & Distribution, Natural Gas Distribution, Energy Services, Midstream Investments and Other Operations. From time to time, we consider the acquisition or the disposition of assets or businesses.

Our 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. 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 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
 
Houston Electric is a transmission and distribution electric utility that operates wholly within the state of Texas. Neither Houston Electric nor any other subsidiary of CenterPoint Energy makes direct retail or wholesale sales of electric energy or owns or operates any electric generating facilities.

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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 kilovolts 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.
 
Electric Distribution
 
In ERCOT, end users purchase their electricity directly from certificated REPs. Houston Electric delivers electricity for REPs in its certificated service area by carrying lower-voltage power from the substation to the retail electric customer. Houston Electric’s distribution network receives electricity from the transmission grid through power distribution substations and delivers electricity to end users 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.
 
ERCOT Market Framework
 
Houston Electric is a member of ERCOT. Within ERCOT, prices for wholesale generation and retail electric sales are unregulated, but services provided by transmission and distribution companies, such as Houston Electric, are regulated by the PUCT. ERCOT serves as the regional reliability coordinating council for member electric power systems in most of Texas. ERCOT membership is open to consumer groups, investor and municipally-owned electric utilities, rural electric cooperatives, independent generators, power marketers, river authorities and REPs. The ERCOT market includes most of the State of Texas, other than a portion of the panhandle, portions of the eastern part of the state bordering Arkansas and Louisiana and the area in and around El Paso. The ERCOT market represents approximately 90% of the demand for power in Texas and is one of the nation’s largest power markets. The ERCOT market included available generating capacity of over 78,000 megawatts as of December 31, 2016 . Currently, there are only limited direct current interconnections between the ERCOT market and other power markets in the United States and Mexico.
 
The ERCOT market operates under the reliability standards set by the NERC and approved by the FERC. Within ERCOT, these reliability standards are administered by the TRE. 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. The ERCOT ISO is responsible for operating the bulk electric power supply system in the ERCOT market. Its responsibilities include ensuring that electricity production and delivery are accurately accounted for among the generation resources and wholesale buyers and sellers.
 
Houston Electric’s electric transmission business, along with those of other owners of transmission facilities in Texas, supports the operation of the ERCOT ISO. The transmission business has planning, design, construction, operation and maintenance responsibility for the portion of the transmission grid and for the load-serving substations it owns, primarily within its certificated area. Houston Electric participates with the ERCOT ISO and other ERCOT utilities to plan, design, obtain regulatory approval for and construct new transmission lines necessary to increase bulk power transfer capability and to remove existing constraints on the ERCOT transmission grid.
 
Restructuring of the Texas Electric Market
 
In 1999, the Texas legislature adopted the Texas Electric Choice Plan (Texas electric restructuring law). Pursuant to that legislation, integrated electric utilities operating within ERCOT were required to unbundle their integrated operations into separate retail sales, power generation and transmission and distribution companies. The legislation provided for a transition period to move to the new market structure and provided a mechanism for the formerly integrated electric utilities to recover stranded and certain other costs resulting from the transition to competition. Those costs were recoverable after approval by the PUCT either through the issuance of securitization bonds or through the implementation of a competition transition charge as a rider to the utility’s tariff. Houston Electric’s integrated utility business was restructured in accordance with the Texas electric restructuring law and its generating stations were sold to third parties. Ultimately Houston Electric was authorized to recover a total of approximately $5 billion in stranded costs, other charges and related interest.  Most of that amount was recovered through the issuance of transition bonds by special purpose subsidiaries of Houston Electric.  The transition bonds are repaid through charges imposed on customers in Houston Electric’s service territory.  As of December 31, 2016 , approximately $1.9 billion aggregate principal amount of transition bonds were outstanding.

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Customers
 
Houston Electric serves nearly all of the Houston/Galveston metropolitan area. At December 31, 2016 , Houston Electric’s customers consisted of approximately 64 REPs, which sell electricity to more than 2.4 million metered customers in Houston Electric’s certificated service area, and municipalities, electric cooperatives and other distribution companies located outside Houston Electric’s certificated service area. Each REP is licensed by, and must meet minimum creditworthiness criteria established by, the PUCT.
 
Sales to REPs that are affiliates of NRG represented approximately 34%, 35% and 37% of Houston Electric’s transmission and distribution revenues in 2016 , 2015 and 2014 , respectively.  Sales to REPs that are affiliates of Energy Future Holdings represented approximately 11%, 10% and 10% of Houston Electric’s transmission and distribution revenues in 2016 , 2015 and 2014 , respectively.  Houston Electric’s aggregate billed receivables balance from REPs as of December 31, 2016 was $193 million.  Approximately 33% and 12% of this amount was owed by affiliates of NRG and Energy Future Holdings, respectively. 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.
 
AMS
 
In May 2012, Houston Electric substantially completed the deployment of an AMS, having installed approximately 2.2 million smart meters. To recover the cost of the AMS, the PUCT approved a monthly surcharge payable by REPs, initially over 12 years and later reduced to six years as a result of DOE grant funds. The surcharge expired in 2015 and 2016 for residential customers and certain non-residential customers, respectively, and is set to expire in 2017 for the remaining non-residential customers. The surcharge amounts and duration are subject to adjustment in future proceedings to reflect actual costs incurred and to address required changes in scope. 
 
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. We know of no other party intending to enter this business in Houston Electric’s 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 electric distribution services but has not been a significant factor to date.
 
Seasonality
 
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 that REP. Thus, 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.
 
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 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.
 
As of December 31, 2016 , Houston Electric had approximately $2.6 billion aggregate principal amount of general mortgage bonds outstanding under the General Mortgage, including approximately $118 million held in trust to secure pollution control bonds for which we are obligated. Additionally, as of December 31, 2016 , Houston Electric had approximately $102 million aggregate principal amount of first mortgage bonds outstanding under the Mortgage. Houston Electric may issue additional general

3



mortgage bonds on the basis of retired bonds, 70% of property additions or cash deposited with the trustee. Approximately $4.1 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, 2016 . However, Houston Electric has contractually agreed that it will not issue additional first mortgage bonds, subject to certain exceptions.

Electric Lines - Overhead.   As of December 31, 2016 , Houston Electric owned 28,702 pole miles of overhead distribution lines and 3,692 circuit miles of overhead transmission lines, including 287 circuit miles operated at 69,000 volts, 2,188 circuit miles operated at 138,000 volts and 1,217 circuit miles operated at 345,000 volts.
 
Electric Lines - Underground.   As of December 31, 2016 , Houston Electric owned 23,937 circuit miles of underground distribution lines and 26 circuit miles of underground transmission lines, including two circuit miles operated at 69,000 volts and 24 circuit miles operated at 138,000 volts.

Substations.   As of December 31, 2016 , Houston Electric owned 232 major substation sites having a total installed rated transformer capacity of 60,854 megavolt amperes.
 
Service Centers.   Houston Electric operates 14 regional service centers located on a total of 292 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

CERC Corp.’s NGD engages in regulated intrastate natural gas sales to, and natural gas transportation and storage for, approximately 3.4 million residential, commercial, industrial and transportation customers in Arkansas, Louisiana, Minnesota, Mississippi, Oklahoma and Texas. The largest metropolitan areas served in each state by NGD are Houston, Texas; Minneapolis, Minnesota; Little Rock, Arkansas; Shreveport, Louisiana; Biloxi, Mississippi; and Lawton, Oklahoma. In 2016 , approximately 37% of NGD’s total throughput was to residential customers and approximately 63% was to commercial and industrial and transportation customers.
 
The table below reflects the number of NGD customers by state as of December 31, 2016 :
 
Residential
 
Commercial/
Industrial
 
Total Customers
Arkansas
379,117

 
48,161

 
427,278

Louisiana
230,475

 
16,842

 
247,317

Minnesota
778,731

 
69,856

 
848,587

Mississippi
112,992

 
12,548

 
125,540

Oklahoma
89,419

 
10,785

 
100,204

Texas
1,592,804

 
97,614

 
1,690,418

Total NGD
3,183,538

 
255,806

 
3,439,344

 
NGD also provides unregulated services in Minnesota consisting of residential appliance repair and maintenance services along with HVAC equipment sales.
 
Seasonality

The demand for intrastate natural gas sales to residential customers and natural gas sales and transportation for commercial and industrial customers is seasonal. In 2016 , approximately 66% of 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.
 

4



Supply and Transportation.   In 2016 , 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 2016 included the following:
Supplier
 
Percent of Supply Volumes
BP Energy Company/BP Canada Energy Marketing
 
17.7%
Macquarie Energy
 
16.3%
Tenaska Marketing Ventures
 
14.0%
Sequent Energy Management
 
8.0%
Kinder Morgan Tejas Pipeline/Kinder Morgan Texas Pipeline
 
7.1%
One Nation Energy Solutions
 
3.3%
Laclede Energy Resources
 
2.9%
Mieco
 
2.6%
CES
 
2.5%
Twin Eagle Resource Management
 
2.2%

Numerous other suppliers provided the remaining 23.4% of NGD’s natural gas supply requirements. 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. NGD anticipates that these gas supply and transportation contracts will be renewed or replaced prior to their expiration.
 
NGD actively engages in commodity price stabilization pursuant to annual gas supply plans presented to and/or filed with each of its state regulatory authorities. These price stabilization activities include use of storage gas and contractually establishing structured prices (e.g., fixed price, costless collars and caps) with our 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 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.
 
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. NGD may also supplement contracted supplies and storage from time to time with stored LNG and propane-air plant production.
 
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, 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.
 
NGD has had AMAs associated with its utility distribution service in Arkansas, Louisiana, Mississippi, Oklahoma and Texas.  Generally, AMAs are contracts between NGD and an asset manager that are intended to transfer the working capital obligation and maximize the utilization of the assets. In these agreements, NGD agrees to release transportation and storage capacity to other parties to manage natural gas storage, supply and delivery arrangements for NGD and to use the released capacity for other purposes when it is not needed for NGD. NGD is compensated by the asset manager through payments made over the life of the agreements based in part on the results of the asset optimization.  NGD has an obligation to purchase its winter storage requirements that have been released to the asset manager under these AMAs. NGD has received approval from the state regulatory commissions in Arkansas, Louisiana, Mississippi and Oklahoma to retain a share of the AMA proceeds. NGD currently has AMAs in Arkansas, north Louisiana and Oklahoma that extend through 2020.

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Assets
 
As of December 31, 2016 , NGD owned approximately 74,000 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 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 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
 
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 NGD’s facilities and market and sell and/or transport natural gas directly to commercial and industrial customers.

Energy Services

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.
In 2016 , CES marketed approximately 777 Bcf of natural gas, related energy services and transportation to approximately 31,000 customers (including approximately 8 Bcf to affiliates) in 31 states. These totals include approximately 13,000 customers and 175 Bcf of natural gas related to the acquisition of Continuum, which closed in April 2016, and was fully integrated into CES by the end of 2016. CES customers vary in size from small commercial customers to large utility companies. Not included in the 2016 customer count are approximately 60,000 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.
In January 2017, CES completed the acquisition of AEM. For information related to this acquisition, see Note 19 to our 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 and hospitals. These services include load forecasting, supply acquisition, daily swing volume management, invoice consolidation, storage asset management, firm and interruptible transportation administration and forward price management. CES also offers a portfolio of physical delivery services designed to meet customers’ supply and price risk management needs. These customers are served directly, through interconnects with various interstate and intrastate pipeline companies, and portably, through our mobile energy solutions business.
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’ processes and risk control environment are designed to measure and value imbalances on a real-time basis to ensure that CES’ 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.
 
Our risk control policy, which is overseen by our 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

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various tools to minimize its supply costs and does not engage in speculative commodity trading. The VaR limit within which CES currently operates, a $4 million maximum set by the board of directors, is consistent with CES’ operational objective of matching its aggregate sales obligations (including the swing associated with load following services) with its supply portfolio in a manner that minimizes its total cost of supply. In 2016 , CES’ VaR averaged $0.2 million with a high of $1.0 million.

Assets
 
CEIP owns and operates 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

Our Midstream Investments business segment consists of CERC Corp.’s equity method investment in Enable. Enable is a publicly traded MLP, jointly controlled by CERC Corp. and OGE. 

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

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

Enable’s Gathering and Processing segment. Enable provides gathering, compression, treating, dehydration, processing and NGLs fractionation for producers who are active in the areas in which Enable operates. Enable’s super-header system is intended to optimize the economics of its natural gas processing and to improve system utilization and reliability.

Enable’s gathering and processing systems compete with gatherers and processors of all types and sizes, including those affiliated with various producers, other major pipeline companies and various independent midstream entities. In the process of selling NGLs, Enable competes against other natural gas processors extracting and selling NGLs. Enable’s primary competitors are master limited partnerships who are active in the regions where it operates.

Enable’s Transportation and Storage segment. Enable provides fee-based interstate and intrastate transportation and storage services across nine states. Enable’s transportation and storage assets were designed and built to serve large natural gas and electric utility companies in its areas of operation.

Enable’s interstate pipelines compete with other interstate and intrastate pipelines. Enable’s intrastate pipeline system competes with numerous interstate and intrastate pipelines, including several of the interconnected pipelines discussed above, as well as other natural gas storage facilities. The principal elements of competition among pipelines are rates, terms of service, and flexibility and reliability of service.

For information related to CERC Corp.’s equity method investment in Enable, see Notes 2(b), 10 and 19 to our consolidated financial statements.

Other Operations

Our Other Operations business segment includes office buildings and other real estate used in our business operations and other corporate operations that support all of our business operations.


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Financial Information About Segments

For financial information about our segments, see Note 18 to our consolidated financial statements, which note is incorporated herein by reference.

REGULATION

We are subject to regulation by various federal, state and local governmental agencies, including the regulations described below.

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 and to impose significant civil and criminal penalties for statutory violations and violations of the FERC’s rules or orders. Our Energy Services business 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 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 TRE. 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, we and our 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

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 customers are primarily based on amounts of energy delivered, whereas distribution rates for a majority of 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, a surcharge related to the implementation of AMS and charges associated with securitization of regulatory assets, stranded costs and restoration costs relating to Hurricane Ike. Transmission rates charged to distribution companies are based on amounts of energy transmitted under “postage stamp” rates that do not vary with the distance the energy is being transmitted. All distribution companies in ERCOT pay Houston Electric the same rates and other charges for transmission services.


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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

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

Substantially all of NGD is subject to cost-of-service rate regulation by the relevant state public utility commissions and, in Texas, by the Railroad Commission and those municipalities served by NGD that have retained original jurisdiction. In certain of its jurisdictions, NGD has in effect annual rate adjustment mechanisms that provide for changes in rates dependent upon certain changes in invested capital, earned returns on equity or actual margins realized.
 
For a discussion of certain of NGD’s ongoing regulatory proceedings, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Regulatory Matters” in Item 7 of Part II of this report, which discussion is incorporated herein by reference.

Department of Transportation
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 at 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. Our 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 increases the maximum civil penalties for pipeline safety administrative enforcement actions; requires the DOT to study and report on the expansion of integrity management requirements and the sufficiency of existing gathering line regulations to ensure safety; requires pipeline operators to verify their records on maximum allowable operating pressure; and imposes 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.

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

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

Interstate Natural Gas Pipeline Regulation

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

Market Behavior Rules; Posting and Reporting Requirements

The EPAct of 2005 amended the NGA to add an anti-manipulation provision that makes it unlawful for any entity to engage in prohibited behavior as prescribed in FERC rules, which were subsequently issued in FERC Order No. 670. The EPAct of 2005 also amends the NGA and the NGPA to give the FERC authority to impose civil penalties for violations of these statutes and FERC’s regulations, rules, and orders, of up to $1 million per day per violation, subject to periodic adjustment to account for inflation. Should Enable fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, it could be subject to substantial penalties and fines. In addition, the CFTC is directed under the CEA to prevent price manipulations for the commodity and futures markets, including the energy futures markets. Pursuant to the Dodd-Frank Act and other authority, the CFTC has adopted anti-market manipulation regulations that prohibit fraud and price manipulation in the commodity and futures markets. The CFTC also has statutory authority to seek civil penalties of up to the greater of $1 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 FERC regulation and 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 Pipeline Regulation

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

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

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




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Crude Oil Gathering Regulation

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

Safety and Health Regulation

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

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

ENVIRONMENTAL MATTERS

Our 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, we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as:

restricting the way we can handle or dispose of wastes;

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

requiring remedial action to mitigate environmental conditions caused by our operations or attributable to former operations;

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

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

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

construct or acquire new facilities and equipment;

acquire permits for facility operations;

modify, upgrade or replace existing and proposed equipment; and

clean or decommission 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 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 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. For example, the EPA has established air emission control requirements for natural gas and NGL production, processing and transportation activities, which may affect Enable’s midstream operations. These include New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds, and the NESHAPS to address hazardous air pollutants frequently associated with natural gas production and processing activities. There can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. We try to anticipate future regulatory requirements that might be imposed and plan accordingly to maintain compliance with changing environmental laws and regulations and to ensure the costs of such compliance are reasonable.

Based on current regulatory requirements and interpretations, we do not believe that compliance with federal, state or local environmental laws and regulations will have a material adverse effect on our business, financial position, results of operations or cash flows. In addition, we believe that our current environmental remediation activities will not materially interrupt or diminish our operational ability. We 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 us to incur significant costs. The following is a discussion of material current environmental and safety laws and regulations that relate to our operations. We believe that we 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. CERC’s revenues, operating costs and capital requirements could be adversely affected as a result of any regulatory action that would require installation of new control technologies or a modification of its operations or would have the effect of reducing the consumption of natural gas. Our electric transmission and distribution business, in contrast to some electric utilities, does not generate electricity and thus is not directly exposed to the risk of high capital costs and regulatory uncertainties that face electric utilities that burn fossil fuels to generate electricity.  Nevertheless, Houston Electric’s revenues could be adversely affected to the extent any resulting regulatory action has the effect of reducing consumption of electricity by ultimate consumers within its 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.  Conversely, regulatory actions that effectively promote the consumption of natural gas because of its lower emissions characteristics would be expected to beneficially affect CERC and its natural gas-related businesses.  At this point in time, however, it would be speculative to try to quantify the magnitude of the impacts from possible new regulatory actions related to GHG emissions, either positive or negative, on our businesses.

To the extent climate changes occur, our businesses may be adversely impacted, though we believe any such impacts are likely to occur very gradually and hence would be difficult to quantify.  To the extent global climate change results in warmer temperatures in our service territories, financial results from our natural gas distribution business could be adversely affected through lower gas sales. On the other hand, warmer temperatures in our electric service territory may increase our 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 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.

Air Emissions

Our 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.

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We 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. We 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 maximum achievable control technology for stationary internal combustion engines (sometimes referred to as the RICE MACT rule). Compressors and back up electrical generators used by our Natural Gas Distribution business segment, and back up electrical generators used by our Electric Transmission & Distribution business segment, are substantially compliant with these laws and regulations.

Water Discharges

Our 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 in wetlands and other waters of the United States unless authorized by an appropriately issued permit. Any unpermitted release of petroleum or other pollutants from our pipelines or facilities could result in fines or penalties as well as significant remedial obligations.

Hazardous Waste

Our 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. Such classes of persons 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 excluded from CERCLA’s definition of a “hazardous substance,” in the course of our ordinary operations we generate wastes that may fall within the definition of a “hazardous substance.” CERCLA authorizes the EPA and, in some cases, third parties to take action in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. Under CERCLA, we could 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 the costs of certain health studies.

Liability for Preexisting Conditions

For information about preexisting environmental matters, please see Note 15(d).


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EMPLOYEES

As of December 31, 2016 , we had 7,727  full-time employees.  The following table sets forth the number of our employees by business segment as of December 31, 2016 :
Business Segment
 
Number
 
Number
Represented
by Collective
Bargaining Groups
Electric Transmission & Distribution
 
2,738

 
1,396

Natural Gas Distribution
 
3,246

 
1,179

Energy Services
 
221

 

Other Operations
 
1,522

 
126

Total
 
7,727

 
2,701


As of December 31, 2016, approximately 35% of our employees were covered by collective bargaining agreements. The collective bargaining agreement with the IBEW Local 66 and the two collective bargaining agreements with Professional Employees International Union Local 12, which collectively cover approximately 21% of our employees, expired in March and May of 2016, respectively. We successfully negotiated all three follow-on agreements in 2016. The new collective bargaining agreement with the IBEW Local 66 expires in May of 2020, and the two new collective bargaining agreements with Professional Employees International Union Local 12 expire in March and May of 2021.

The collective bargaining agreements with Gas Workers Union, Local 340 and the IBEW, Local 949, covering approximately 8% of our employees, will expire in April and December of 2020, respectively. These two agreements were last negotiated in 2015.

The two collective bargaining agreements with the United Steelworkers Union, Locals 13-227 and 13-1, which cover approximately 6% of our employees, are scheduled to expire in June and July of 2017, respectively. We believe we have good relationships with these bargaining units and expect to negotiate new agreements in 2017.

EXECUTIVE OFFICERS
(as of February 10, 2017)
Name
 
Age
 
Title
Milton Carroll
 
66
 
Executive Chairman
Scott M. Prochazka
 
50
 
President and Chief Executive Officer and Director
William D. Rogers
 
56
 
Executive Vice President and Chief Financial Officer
Tracy B. Bridge
 
58
 
Executive Vice President and President, Electric Division
Joseph B. McGoldrick (1)
 
63
 
Executive Vice President and President, Gas Division
Dana C. O’Brien
 
49
 
Senior Vice President, General Counsel and Corporate Secretary
Sue B. Ortenstone
 
60
 
Senior Vice President and Chief Human Resources Officer
(1) On January 4, 2017, Mr. McGoldrick announced his intent to retire on March 1, 2017.

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 Healthcare 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, general partner of LRR Energy, L.P., from November 2011 to January 2014.

Scott M. Prochazka has served as a Director and President and Chief Executive Officer (CEO) of CenterPoint Energy since January 1, 2014. He previously served as Executive Vice President and Chief Operating Officer from July 2012 to December 2013; as Senior Vice President and Division President, Electric Operations from May 2011 through July 2012; as Division Senior Vice President, Electric Operations of Houston Electric from February 2009 to May 2011; as Division Senior Vice President Regional Operations of CERC from February 2008 to February 2009; and as Division Vice President, Customer Service Operations from October 2006 to February 2008. He currently serves on the Boards of Directors of Enable GP, LLC, the general partner of

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Enable Midstream Partners, LP, Gridwise Alliance, Edison Electric Institute, American Gas Association, Greater Houston Partnership, United Way of Greater Houston and Junior Achievement of South Texas.

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 in a similar role at JPMorgan Chase in New York. He currently serves on the Board of Directors of Enable GP, LLC, the general partner of Enable Midstream Partners, LP.

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. He currently serves as Chair of the Board of Directors of Rebuilding Together Houston.

Joseph B. McGoldrick has served as Executive Vice President and President, Gas Division since February 2014. He previously served as Senior Vice President and Division President, Gas Operations from September 2012 to February 2014; as Senior Vice President and Division President, Energy Services from May 2011 to September 2012, and as Division President, Gas Operations from February 2007 to May 2011. Mr. McGoldrick is a member of the American Gas Association’s Leadership Council.

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

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

Item 1A.
Risk Factors

We are a holding company that conducts all of our business operations through subsidiaries, primarily Houston Electric and CERC. We also own interests in Enable. The following, along with any additional legal proceedings identified or incorporated by reference in Item 3 of this report, summarizes the principal risk factors associated with the businesses conducted by our subsidiaries and our interests in Enable:

Risk Factors Associated with Our Consolidated Financial Condition

As a holding company with no operations of our own, we will depend on distributions from our subsidiaries and from Enable to meet our payment obligations and to pay dividends on our common stock, and provisions of applicable law or contractual restrictions could limit the amount of those distributions.

We derive all of our operating income from, and hold all of our assets through, our subsidiaries, including our interests in Enable. As a result, we depend on distributions from our subsidiaries and Enable to meet our payment obligations and to pay dividends on our common stock. In general, our subsidiaries are separate and distinct legal entities and have no obligation to provide us with funds for our payment obligations, whether by dividends, distributions, loans or otherwise. In addition, provisions of applicable law, such as those limiting the legal sources of dividends, limit our subsidiaries’ ability to make payments or other distributions to us, and our subsidiaries could agree to contractual restrictions on their ability to make distributions. For a discussion

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

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

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

Our businesses are capital intensive in nature. We depend on long-term debt to finance a portion of our capital expenditures and refinance our existing debt and on short-term borrowings through our revolving credit facilities and commercial paper programs to satisfy liquidity needs to the extent not satisfied by cash flow from our business operations. As of December 31, 2016, we had $8.6 billion of outstanding indebtedness on a consolidated basis, which includes $2.3 billion of non-recourse Securitization Bonds. As of December 31, 2016, approximately $850 million principal amount of this debt is required to be paid through 2019. This amount excludes principal repayments of approximately $1.3 billion on Securitization Bonds, for which dedicated revenue streams exist. 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;

maintenance of acceptable credit ratings;

market expectations regarding our future earnings and cash flows;

our ability to access capital markets on reasonable terms;

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

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

provisions of relevant tax and securities laws.

As of December 31, 2016, Houston Electric had approximately $2.6 billion aggregate principal amount of general mortgage bonds outstanding under the General Mortgage, including approximately $118 million held in trust to secure pollution control bonds for which we are obligated. Additionally, as of December 31, 2016, 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, 70% of property additions or cash deposited with the trustee. Approximately $4.1 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, 2016. However, Houston Electric has contractually agreed that it will not issue additional first mortgage bonds, subject to certain exceptions.

Our 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. We note that these credit ratings are not recommendations to buy, sell or hold our securities. Each rating should be evaluated independently of any other rating. Any future reduction or withdrawal of one or more of our credit ratings could have a material adverse impact on our ability to access capital on acceptable terms.


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An impairment of goodwill, long-lived assets, including intangible assets, and equity and cost method investments 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 us to test goodwill for impairment on an annual basis or when events or circumstances occur indicating that goodwill might be impaired. Long-lived assets, including intangible assets with finite useful lives, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable.

For investments we account for under the equity or cost method, the impairment test considers whether the fair value of such investment as a whole, not the underlying net assets, has declined and whether that decline is other than temporary. For example, during the year ended December 31, 2015, we determined that an other than temporary decrease in the value of our equity investment in Enable had occurred. This determination was based on the sustained low Enable common unit price and further declines in such price during the year, as well as the market outlook for continued depressed crude oil and natural gas prices impacting the midstream oil and gas industry. We wrote down the value of our investment in Enable to its estimated fair value which resulted in impairment charges of $1,225 million for the year ended December 31, 2015. Additionally, we recorded our share, $621 million, of impairment charges Enable recorded for goodwill and long-lived assets, for a total impairment charge of $1,846 million.

If Enable’s unit price, distributions or earnings were to decline to levels below those used in our impairment tests in 2015, and that decline is deemed to be other than temporary, we could determine that we are unable to recover the carrying value of our equity investment in Enable. Considerable judgment is used in determining if an impairment loss is other than temporary and the amount of any impairment. A sustained low Enable common unit price could result in our recording further impairment charges in the future. If we determine that an impairment is indicated, we would be required to take an immediate non-cash charge to earnings with a correlative effect on equity and balance sheet leverage as measured by debt to total capitalization.

Poor investment performance of the pension plan, factors adversely affecting the calculation of pension liabilities and increasing health care costs could unfavorably impact our results of operations, liquidity and financial position.

We maintain a qualified defined benefit pension plan covering substantially all employees. Our costs of providing this plan are dependent upon a number of factors including the investment returns on plan assets, the level of interest rates used to calculate the funded status of the plan, our contributions to the plan and government regulations with respect to funding requirements and the calculation of plan liabilities. Funding requirements may increase and we may be required to make unplanned contributions in the event of a decline in the market value of plan assets, a decline in the interest rates used to calculate the present value of future plan obligations or government regulations that increase minimum funding requirements or the pension liability. In addition to affecting our funding requirements, each of these factors could adversely affect our results of operations, liquidity and financial position. Further, increasing health care costs and the effects of health care reform or any future legislative changes could also materially affect our benefit programs and costs. Our costs of providing employee benefits and related funding requirements 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 financial results.

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

We and our subsidiaries use derivative instruments, such as swaps, options, futures and forwards, to manage our commodity, weather and financial market risks. Enable may also use such instruments from time to time to manage its commodity and financial market risk. We, our subsidiaries 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. 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.

Risk Factors Affecting Our Electric Transmission & Distribution Business

Rate regulation of Houston Electric’s business may delay or deny Houston Electric’s ability to earn a reasonable return and fully recover its costs.

Houston Electric’s rates are regulated by certain municipalities and the PUCT based on an analysis of its invested capital, its expenses and other factors in a test year in comprehensive base rate proceedings, subject to periodic review and adjustment using

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mechanisms like those discussed below. 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 control. The rates that Houston Electric is allowed to charge may not match its costs at any given time, which is referred to as “regulatory lag.”

Though several interim adjustment mechanisms have been implemented to reduce the effects of regulatory lag, such adjustment mechanisms are subject to the applicable regulatory body’s approval and are subject to limitations that may reduce Houston Electric’s ability to adjust rates. For example, the DCRF mechanism adjusts an electric utility’s rates for increases in net distribution-invested capital (e.g., distribution plant and intangible plant and communication equipment) since its last comprehensive base rate proceeding, but Houston Electric may make a DCRF filing only once per year and up to four times between comprehensive rate proceedings. 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 twice a year.

Houston Electric can make no assurance that filings for such mechanisms will result in favorable adjustments to rates. Further, 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 costs or enable Houston Electric to earn a reasonable return. In addition, changes to the interim adjustment mechanisms could result in an increase in regulatory lag or otherwise impact Houston Electric’s ability to recover its costs in a timely manner. To the extent the regulatory process does not allow Houston Electric to make a full and timely recovery of appropriate costs, its results of operations, financial condition 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 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. Thus, 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. Unusually mild weather in the warmer months could diminish our results of operations and harm our financial condition. Conversely, extreme warm weather conditions could increase our results of operations in a manner that would not likely be annually recurring.

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

Houston Electric has deployed an AMS throughout its service territory. The deployment consisted, among other elements, of replacing existing meters with new electronic meters that record metering data at 15-minute intervals and wirelessly communicate that information to Houston Electric over a bi-directional communications system installed for that purpose. The AMS 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 associated with a customer’s change in REPs or the connection or disconnection of electric service. Unanticipated difficulties could be encountered during the operation of the AMS, including failures or inadequacy of equipment or software, difficulties in integrating the various components of the AMS, changes in technology, cyber-security issues and factors outside the control of Houston 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 results of operations, financial condition and cash flows.

Houston Electric could be subject to higher costs and fines or other sanctions as a result of mandatory reliability standards.

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. The FERC has designated the NERC as the ERO to promulgate standards, under FERC oversight, for all owners, operators and users of the bulk power system. The FERC has approved the delegation by the NERC of authority for reliability in ERCOT to the TRE, a functionally independent division of ERCOT. Compliance with the mandatory reliability standards may subject Houston Electric to higher operating costs and may result in increased capital expenditures. In addition, if Houston Electric were to be found to be in noncompliance with applicable mandatory reliability standards, it could be subject to sanctions, including substantial monetary penalties.

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A substantial portion of Houston Electric’s receivables is concentrated in a small number of REPs, and any delay or default in payment 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, 2016, Houston Electric did business with approximately 64 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. The PUCT revised its regulations in 2009 to (i) increase the financial qualifications required of REPs that began selling power after January 1, 2009, and (ii) authorize utilities to defer bad debts resulting from defaults by REPs for recovery in a future rate case. A significant portion of Houston Electric’s billed receivables from REPs are from affiliates of NRG and Energy Future Holdings. Houston Electric’s aggregate billed receivables balance from REPs as of December 31, 2016 was $193 million. Approximately 33% and 12% of this amount was owed by affiliates of NRG and Energy Future Holdings, respectively. In April 2014, Energy Future Holdings publicly disclosed that it and the substantial majority of its direct and indirect subsidiaries, excluding Oncor Electric Delivery Company LLC and its subsidiaries, filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the District of Delaware. Any delay or default in payment by REPs could adversely affect Houston Electric’s cash flows, financial condition and results of operations. If a REP were unable to meet its obligations, it could consider, among various options, restructuring under the bankruptcy laws, in which event such REP might seek to avoid honoring its obligations, and claims might be made by creditors involving payments Houston Electric had received from such REP.

Risk Factors Affecting Our Natural Gas Distribution and Energy Services Businesses

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

CERC’s rates for NGD are regulated by certain municipalities (in Texas only) and state commissions in the context of comprehensive base rate proceedings, i.e., general rate cases, based on an analysis of NGD’s invested capital, expenses and other factors in a test year (often either fully or partially historic), subject to periodic review and adjustment. A general rate case is also a very complex and resource intensive proceeding with a relatively long timeline for completion. Thus, the rates that CERC 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 enacted legislation in 2015 allowing public utilities to elect to have their rates regulated pursuant to a FRP, but such legislation provides for a utility’s base rates to be adjusted once a year. In each of Louisiana, Mississippi and Oklahoma, NGD makes annual filings utilizing various formula rate mechanisms that adjust rates based on a comparison of authorized return to actual return to achieve the allowed return rates in those jurisdictions. Additionally, in Minnesota, the MPUC implemented a full revenue decoupling pilot program in 2015, which separates approved revenues from the amount of natural gas used by its customers. The effectiveness of these filings and programs depends on the approval of the applicable state regulatory body.

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

NGD can make no assurances that such filings will result in favorable adjustments to its rates. Notwithstanding the application of the rate mechanisms discussed above, the regulatory process in which rates are determined may not always result in rates that will produce full recovery of NGD’s costs and enable NGD to earn a reasonable return on its invested capital. 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.


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CERC’s natural gas distribution and energy services businesses, including transportation and storage, are subject to fluctuations in notional natural gas prices as well as geographic and seasonal natural gas price differentials, which could affect the ability of CERC’s suppliers and customers to meet their obligations or otherwise adversely affect CERC’s liquidity and results of operations and financial condition.

CERC is subject to risk associated with changes in the notional price of natural gas as well as geographic and seasonal natural gas price differentials. Increases in natural gas prices might affect CERC’s ability to collect balances due from its customers and, for NGD, could create the potential for uncollectible accounts expense to exceed the recoverable levels built into CERC’s tariff rates. In addition, a sustained period of high natural gas prices could (i) decrease demand for natural gas in the areas in which CERC operates, thereby resulting in decreased sales and revenues and (ii) increase the risk that CERC’s suppliers or customers fail or are unable to meet their obligations. An increase in natural gas prices would also increase CERC’s working capital requirements by increasing the investment that must be made in order to maintain natural gas inventory levels. Additionally, a decrease in natural gas prices could increase the amount of collateral that CERC must provide under its hedging arrangements.

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.

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.

CERC’s revenues and results of operations are seasonal.

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

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

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

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

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

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


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Risk Factors Affecting Our Interests in Enable Midstream Partners, LP

We hold a substantial limited partnership interest in Enable (54.1% of Enable’s outstanding limited partnership interests as of December 31, 2016), as well as 50% of the management rights in Enable’s general partner and a 40% interest in the incentive distribution rights held by Enable’s general partner. As of December 31, 2016, we owned an aggregate of 14,520,000 Series A Preferred Units in Enable. Accordingly, our future earnings, results of operations, cash flows and financial condition will be affected by the performance of Enable, the amount of cash distributions we receive from Enable and the value of our interests in Enable. Factors that may have a material impact on Enable’s performance and cash distributions, and, hence, the value of our interests in Enable, include the risk factors outlined below, as well as the risks described elsewhere under “Risk Factors” that are applicable to Enable.

Our cash flows will be adversely impacted if we receive less cash distributions from Enable than we currently expect.

Both CERC Corp. and OGE hold their limited partnership interests in Enable in the form of both common units and subordinated units. We also hold Series A Preferred Units in Enable. For its Series A Preferred Units, Enable is expected to pay $0.625 per Series A Preferred Unit, or $2.50 per Series A Preferred Unit on an annualized basis. However, distributions on each Series A Preferred Unit are not mandatory and are non-cumulative in the event distributions are not declared on the 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 and subordinated units to the extent it has sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to its general partner and its affiliates (referred to as “available cash”). The principal difference between Enable’s common units and subordinated units is that in any quarter during the applicable subordination period, holders of the subordinated units are not entitled to receive any distribution of available cash until the common units have received the minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution on common units from prior quarters. If Enable does not pay distributions on its subordinated units, its subordinated units will not accrue arrearages for those unpaid distributions. Accordingly, if Enable is unable to pay its minimum quarterly distribution, the amount of cash distributions we receive from Enable may be adversely affected. Enable may not have sufficient available cash each quarter to enable it to pay the minimum quarterly distribution or to pay distributions on the Series A Preferred Units. Additionally, distributions on the Series A Preferred Units reduce the amount of available cash Enable has to pay distributions on its common and subordinated units. The amount of cash Enable can distribute on its common and subordinated units and its 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 midstream energy companies;

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;


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its debt service requirements and other liabilities;

fluctuations in its working capital needs;

its ability to borrow funds and access capital markets;

restrictions contained in its debt agreements;

the amount of cash reserves established by its general partner;

distributions paid on its Series A Preferred Units; and

other business risks affecting its cash levels.

The amount of cash Enable has available for distribution to us on its common and subordinated units and 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 and subordinated units and 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’s Series A Preferred Units are required to be redeemed in certain circumstances if they are not eligible for trading on the NYSE, and Enable may not have sufficient funds to redeem its Series A Preferred Units if required to do so.

As a holder of Enable’s Series A Preferred Units, we may request that Enable list those units for trading on the NYSE. If Enable is unable to list the Series A Preferred Units in certain circumstances, it will be required to redeem the Series A Preferred Units. There can be no assurance that Enable would have sufficient financial resources available to satisfy its obligation to redeem the Series A Preferred Units. In addition, mandatory redemption of the 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.

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

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

Although we jointly control Enable with OGE, we may have conflicts of interest with Enable that could subject us to claims that we have breached our fiduciary duty to Enable and its unitholders.

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

Enable’s contracts are subject to renewal risks.

As contracts with its existing suppliers and customers expire, Enable may have to negotiate extensions or renewals of those contracts or enter into new contracts with other suppliers and customers. Enable may be unable to extend or renew existing contracts or enter into new contracts on favorable commercial terms, if at all. Depending on prevailing market conditions at the time of an extension or renewal, gathering and processing customers with fee based contracts may desire to enter into contracts under different fee arrangements. Approximately 87% of Enable’s gross margin was generated from fee-based contracts during the year ended December 31, 2016. Likewise, Enable’s transportation and storage customers may choose not to extend or renew expiring contracts

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based on the economics of the related areas of production. 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.

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

For the year ended December 31, 2016, 49% of Enable’s gathered natural gas volumes were attributable to the affiliates of Continental, Vine, GeoSouthern, XTO Energy and Apache and 51% of its transportation and storage service revenues were attributable to affiliates of CenterPoint Energy, Spire, XTO Energy, American Electric Power Company and OGE.

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

Enable’s businesses are dependent, in part, on the drilling and production decisions of others.

Enable’s businesses are dependent on the drilling and production of natural gas and crude oil. Enable has no control over the level of drilling activity in its areas of operation, or the amount of natural gas, NGL or crude oil reserves associated with wells connected to its systems. In addition, as the rate at which production from wells currently connected to its systems naturally declines over time, Enable’s gross margin associated with those wells will also decline. To maintain or increase throughput levels on its gathering and transportation systems and the asset utilization rates at its natural gas processing plants, Enable’s customers must continually obtain new natural gas, NGL and crude oil supplies. The primary factors affecting Enable’s ability to obtain new supplies of natural gas, NGLs and crude oil and attract new customers to its assets are the level of successful drilling activity near its systems, its ability to compete for volumes from successful new wells and its ability to expand its capacity as needed. If Enable is not able to obtain new supplies of natural gas, NGLs and crude oil to replace the natural decline in volumes from existing wells, throughput on its gathering, processing, transportation and storage facilities will decline, which could adversely affect its financial position, results of operations and ability to make cash distributions. Enable has no control over producers or their drilling and production decisions, which are affected by, among other things:

the availability and cost of capital;

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

demand for natural gas, NGLs and crude oil;

levels of reserves;

geological considerations;

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

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

Fluctuations in energy prices can also greatly affect the development of new natural gas, NGL and crude oil reserves. Drilling and production activity generally decreases as commodity prices decrease. In general terms, the prices of natural gas, NGLs, crude oil and other hydrocarbon products fluctuate in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond Enable’s control. Because of these factors, even if new natural gas, NGL or crude oil reserves are known to exist in areas served by Enable’s assets, producers may choose not to develop those reserves. Declines in natural gas, NGL or crude oil prices can have a negative impact on exploration, development and production activity and, if sustained, could lead to decreases in such activity. In early 2016, natural gas and crude oil prices dropped to their lowest levels in over 10 years. Both natural gas and crude oil prices increased moderately in the second half of 2016. Sustained low natural gas, NGL or crude oil prices could also lead producers to shut in production from their existing wells. Sustained reductions in exploration or production activity in Enable’s areas of operation could lead to further reductions in the utilization of its systems, which could adversely affect Enable’s financial position, results of operations and ability to make cash distributions.

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In addition, it may be more difficult to maintain or increase the current volumes on Enable’s gathering systems and processing plants, as several of the formations in the unconventional resource plays in which it operates generally have higher initial production rates and steeper production decline curves than wells in more conventional basins. Should Enable determine that the economics of its gathering assets do not justify the capital expenditures needed to grow or maintain volumes associated therewith, Enable may reduce such capital expenditures, which could cause revenues associated with these assets to decline over time. In addition to capital expenditures to support growth, the steeper production decline curves associated with unconventional resource plays may require Enable to incur higher maintenance capital expenditures relative to throughput over time, which will reduce its distributable cash flow.

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

Enable’s industry is highly competitive, and increased competitive pressure could adversely affect its financial position, results of operations and ability to make cash distributions.

Enable competes with similar enterprises in its respective areas of operation. The principal elements of competition are rates, terms of service and flexibility and reliability of service. Enable’s competitors include large energy companies that have greater financial resources and access to supplies of natural gas, NGLs and crude oil than Enable. Some of these competitors may expand or construct gathering, processing, transportation and storage systems that would create additional competition for the services Enable provides to its customers. Excess pipeline capacity in the regions served by Enable’s interstate pipelines could also increase competition and adversely impact Enable’s ability to renew or enter into new contracts with respect to its available capacity when existing contracts expire. In addition, Enable’s customers that are significant producers of natural gas or crude oil may develop their own gathering, processing, transportation and storage systems in lieu of using Enable’s systems. Enable’s ability to renew or replace existing contracts with its customers at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of its competitors and customers. Further, natural gas utilized as a fuel competes with other forms of energy available to end users, including electricity, coal and liquid fuels. Increased demand for such forms of energy at the expense of natural gas could lead to a reduction in demand for natural gas gathering, processing, transportation and storage services. All of these competitive pressures could adversely affect Enable’s financial position, results of operations and ability to make cash distributions.

Enable may not be able to recover the costs of its substantial planned investment in capital improvements and additions, and the actual cost of such improvements and additions may be significantly higher than it anticipates.

Enable’s business plan calls for investment in capital improvements and additions. In Enable’s Form 10-K for the year ended December 31, 2016, Enable stated that it expects that its expansion capital could range from approximately $455 million to $575 million and its maintenance capital could range from approximately $95 million to $125 million for the year ending December 31, 2017. In the second quarter of 2016, Enable delayed the completion of the Wildhorse Plant, a cryogenic processing facility that it plans to connect to its super-header system in Garvin County, Oklahoma. Enable also plans to construct natural gas gathering and compression infrastructure to support producer activity.

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


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

Natural gas, NGL and crude oil prices are volatile, and changes in these prices could adversely affect Enable’s financial position, results of operations and ability to make cash distributions.

Enable’s financial position, results of operations and ability to make cash distributions could be negatively affected by adverse movements in the prices of natural gas, NGLs and crude oil depending on factors that are beyond Enable’s control. These factors include demand for these commodities, which fluctuates with changes in market and economic conditions and other factors, including the impact of seasonality and weather, general economic conditions, the level of domestic and offshore natural gas production and consumption, the availability of imported natural gas, LNG, NGLs and crude oil, actions taken by foreign natural gas and oil producing nations, the availability of local, intrastate and interstate transportation systems, the availability and marketing of competitive fuels, the impact of energy conservation efforts, technological advances affecting energy consumption and the extent of governmental regulation and taxation. In early 2016, natural gas and crude oil prices dropped to their lowest levels in over 10 years. Both natural gas and crude oil prices increased moderately in the second half of 2016.

Enable’s natural gas processing arrangements expose it to commodity price fluctuations. In 2016, 8%, 46%, and 46% of Enable’s processing plant inlet volumes consisted of keep-whole arrangements, percent-of-proceeds or percent-of-liquids and fee-based, respectively. Under a typical keep-whole arrangement, Enable processes raw natural gas, extracts the NGLs, replaces the extracted NGLs with a Btu equivalent amount of natural gas, delivers the processed and replacement natural gas to the producer, retains the NGLs and sells the NGLs for its own account. If Enable is unable to sell the NGLs extracted for more than the cost of the replacement natural gas, the margins on its sale of goods will be negatively affected.

Under a typical percent-of-proceeds processing arrangement, Enable purchases raw natural gas at a cost that is based on the amount of natural gas and NGLs contained in the raw natural gas. Enable then processes the raw natural gas, extracts the NGLs and sells the processed natural gas and NGLs for its own account. If Enable is unable to sell the processed natural gas and NGLs for more than the cost of the raw natural gas, the margins on its sale of goods will be negatively affected.

Under a typical percent-of-liquids processing arrangement and a typical fee-based arrangement, Enable purchases a portion of the raw natural gas that is equivalent to the amount of NGLs it contains, processes the raw natural gas, extracts the NGLs, returns the processed natural gas to the producer and sells the NGLs for its own account. If Enable is unable to sell the processed natural gas and NGLs for more than the cost of raw natural gas, the margins on its sale of goods will be negatively affected.

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

Enable is exposed to credit risks of its customers, and any material nonpayment or nonperformance by its key customers could adversely affect its financial position, results of operations and ability to make cash distributions.

Some of Enable’s customers may experience financial problems that could have a significant effect on their creditworthiness. Severe financial problems encountered by its customers could limit Enable’s ability to collect amounts owed to it, or to enforce performance of obligations under contractual arrangements. In addition, many of Enable’s customers finance their activities through cash flow from operations, the incurrence of debt or the issuance of equity. The combination of reduction of cash flow resulting from declines in commodity prices, a reduction in borrowing bases under reserve-based credit facility and the lack of availability of debt or equity financing may result in a significant reduction of its customers’ liquidity and limit their ability to make payment or perform on their obligations to Enable. Furthermore, some of Enable’s customers may be highly leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to Enable. Financial problems experienced by Enable’s customers could result in the impairment of its assets, reduction of its operating cash flows and may also reduce or curtail their future use of its products and services, which could reduce Enable’s revenues.

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Enable provides certain transportation and storage services under fixed-price “negotiated rate” contracts that are not subject to adjustment, even if its cost to perform such services exceeds the revenues received from such contracts, and, as a result, Enable’s costs could exceed its revenues received under such contracts.

Enable has been authorized by the FERC to provide transportation and storage services at its facilities at negotiated rates. Generally, negotiated rates are in excess of the maximum recourse rates allowed by the FERC, but it is possible that costs to perform services under “negotiated rate” contracts will exceed the revenues obtained under these agreements. If this occurs, it could decrease the cash flow realized by Enable’s systems and, therefore, decrease the cash it has available for distribution.

As of December 31, 2016, approximately 54% of Enable’s contracted firm transportation capacity and 44% of its contracted firm storage capacity was subscribed under such “negotiated rate” contracts. These contracts generally do not include provisions allowing for adjustment for increased costs due to inflation, pipeline safety activities or other factors that are not tied to an applicable tracking mechanism authorized by the FERC. Successful recovery of any shortfall of revenue, representing the difference between “recourse rates” (if higher) and negotiated rates, is not assured under current FERC policies.

If third-party pipelines and other facilities interconnected to Enable’s gathering, processing or transportation facilities become partially or fully unavailable for any reason, Enable’s financial position, results of operations and ability to make cash distributions could be adversely affected.

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

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

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

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

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

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

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

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

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Enable may be unable to control the amount of cash it will receive from the joint venture;

Enable may incur liabilities as a result of an action taken by its joint venture partners;

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

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

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

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

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

Enable’s ability to grow is dependent on its ability to access external financing sources.

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

To the extent Enable issues additional units 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 on access to the capital markets to fund its expansion capital expenditures. Historically, unit prices of midstream master limited partnerships have experienced periods of volatility. In addition, because Enable’s common units are yield-based securities, rising market interest rates could impact the relative attractiveness of its common units to investors. As a result of capital market volatility, Enable may be unable to issue equity or debt on satisfactory terms, or at all, which may limit its ability to expand its operations or make future acquisitions.

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

As of December 31, 2016, Enable had approximately $3.0 billion of long-term debt outstanding, excluding the premiums on their senior notes. Enable has a $1.75 billion revolving credit facility for working capital, capital expenditures and other partnership purposes, including acquisitions, of which $1.1 billion was available as of February 1, 2017. Enable will continue to have 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;

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

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

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

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

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

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

permit its subsidiaries to incur or guarantee additional debt;

incur or permit to exist certain liens on assets;

dispose of assets;

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

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

change the nature of its business.

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

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

Enable may be unable to obtain or renew permits necessary for its operations, which could inhibit its ability to do business.

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

Additionally, in order to obtain permits and renewals of permits and other approvals in the future, Enable may be required to prepare and present data to governmental authorities pertaining to the potential adverse impact that any proposed pipeline or processing-related activities may have on the environment, individually or in the aggregate, including on public and Indian lands.

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Certain approval procedures may require preparation of archaeological surveys, endangered species studies and other studies to assess the environmental impact of new sites or the expansion of existing sites. Compliance with these regulatory requirements is expensive and significantly lengthens the time required to prepare applications and to receive authorizations.

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

Enable is subject to extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, waste management, wildlife conservation, natural resources and health and safety that could, among other things, delay or increase its costs of construction, restrict or limit the output of certain facilities and/or require additional pollution control equipment and otherwise increase costs. For instance, in May 2016, the EPA issued final New Source Performance Standards governing methane emissions imposing more stringent controls on methane and volatile organic compounds emissions at new and modified oil and natural gas production, processing, storage and transmission facilities. These rules have required changes to Enable’s operations, including the installation of new equipment to control emissions. The EPA has also announced that it intends to impose methane emission standards for existing sources and has issued information collection requests to companies with production, gathering and boosting, gas processing, storage, and transmission facilities. Additionally, several states are pursuing similar measures to regulate emissions of methane from new and existing sources. There are significant capital, operating and other costs associated with compliance with these environmental statutes, rules and regulations. As a result of this continued regulatory focus, future federal and state regulations relating to Enable’s gathering and processing, transmission, and storage operations remain a possibility and could result in increased compliance costs on its operations. Furthermore, if new or more stringent federal, state or local legal restrictions are adopted in areas where Enable’s oil and natural gas exploration and production customers operate, they could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells, some or all of which could adversely affect demand for Enable’s services to those customers.

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

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

Hydraulic fracturing is common practice that is used by many of Enable’s customers to stimulate production of natural gas and crude oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand, and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing typically is regulated by state oil and natural gas commissions. In addition, certain federal agencies have proposed additional laws and regulations to more closely regulate the hydraulic fracturing process. For example, in May 2016, the EPA issued final new source performance standard requirements that impose more stringent controls on methane and volatile organic compounds emissions from oil and gas development and production operations, including hydraulic fracturing and other well completion activity. The EPA also released the final results of its comprehensive research study on the potential adverse impacts that hydraulic fracturing may have on drinking water resources in December 2016. The EPA concluded that hydraulic fracturing activities can impact drinking water resources under some circumstances, including large volume spills and inadequate mechanical

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integrity of wells. The results of EPA’s study could spur action towards federal legislation and regulation of hydraulic fracturing or similar production operations. In past sessions, Congress has considered, but not passed, legislation to provide for federal regulation of hydraulic fracturing under the Safe Drinking Water Act and to require disclosure of the chemicals used in the hydraulic fracturing process. The EPA has issued the Safe Water Drinking Act permitting guidance for hydraulic fracturing operations involving the use of diesel fuel in fracturing fluids in those states where the EPA is the permitting authority. Additionally, the Bureau of Land Management issued final rules to regulate hydraulic fracturing on federal lands in March 2015. Although these rules were struck down by a federal court in Wyoming in June 2016, an appeal of the decision is still pending.

Some states have adopted, and other states are considering adopting, legal requirements that could impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing activities. Local government also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular, in some cases banning hydraulic fracturing entirely. If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where Enable’s oil and natural gas exploration and production customers operate, they could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells, some or all of which activities could adversely affect demand for Enable’s services to those customers.

State and federal regulatory agencies recently have focused on a possible connection between the operation of injection wells used for oil and gas waste disposal and seismic activity. Similar concerns have been raised that hydraulic fracturing may also contribute to seismic activity. When caused by human activity, such events are called induced seismicity. In March 2016, the United States Geological Survey identified six states with the most significant hazards from induced seismicity, including Oklahoma, Kansas, Texas, Colorado, New Mexico and Arkansas. In light of these concerns, some state regulatory agencies have modified their regulations or issued orders to address induced seismicity. For example, the OCC has implemented volume reduction plans, and at times required shut-ins, for disposal wells injecting wastewater from oil and gas operations into the Arbuckle formation. The OCC also recently released well completion seismicity guidelines for operators in the South Central Oklahoma Oil Province and the Sooner Trend Anadarko Basin Canadian and Kingfisher Counties that call for hydraulic fracturing operations to be suspended following earthquakes of certain magnitudes in the vicinity. Certain environmental and other groups have also suggested that additional federal, state and local laws and regulations may be needed to more closely regulate the hydraulic fracturing process. Enable cannot predict whether additional federal, state or local laws or regulations applicable to hydraulic fracturing will be enacted in the future and, if so, what actions any such laws or regulations would require or prohibit. Increased regulation and attention given to induced seismicity could lead to greater opposition to, and litigation concerning, oil and gas activities utilizing hydraulic fracturing or injection wells for waste disposal. Additional legislation or regulation could also lead to operational delays or increased operating costs for Enable’s customers, which in turn could reduce the demand for Enable’s services.

Other governmental agencies, including the DOE, have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the Safe Drinking Water Act or other regulatory mechanisms.

Enable’s operations are subject to extensive regulation by federal, state and local regulatory authorities. Changes or additional regulatory measures adopted by such authorities could adversely affect Enable’s financial position, results of operations and ability to make cash distributions.

The rates charged by several of Enable’s pipeline systems, including for interstate gas transportation service provided by its intrastate pipelines, are regulated by the FERC. Enable’s pipeline operations that are not regulated by the FERC may be subject to state and local regulation applicable to intrastate natural and transportation services. The relevant states in which Enable operates include North Dakota, Oklahoma, Arkansas, Louisiana, Texas, Missouri, Kansas, Mississippi, Tennessee and Illinois.

The FERC and state regulatory agencies also regulate other terms and conditions of the services Enable may offer. If one of these regulatory agencies, on its own initiative or due to challenges by third parties, were to lower its tariff rates or deny any rate increase or other material changes to the types, or terms and conditions, of service Enable might propose or offer, the profitability of Enable’s pipeline businesses could suffer. If Enable were permitted to raise its tariff rates for a particular pipeline, there might be significant delay between the time the tariff rate increase is approved and the time that the rate increase actually goes into effect, which could also limit its profitability. Furthermore, competition from other pipeline systems may prevent Enable from raising its tariff rates even if regulatory agencies permit it to do so. The regulatory agencies that regulate Enable’s systems periodically implement new rules, regulations and terms and conditions of services subject to their jurisdiction. New initiatives or orders may adversely affect the rates charged for Enable’s services or otherwise adversely affect its financial position, results of operations and cash flows and ability to make cash distributions.


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A change in the jurisdictional characterization of some of Enable’s assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of its assets, which may cause its revenues to decline and operating expenses to increase.

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

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

Other Risk Factors Affecting Our Businesses or Our Interests in Enable Midstream Partners, LP

We are subject to operational and financial risks and liabilities arising from environmental laws and regulations.

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

restricting the way we can handle or dispose of wastes;

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

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

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

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

To comply with these requirements, we 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;

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modify or replace existing and proposed equipment; and

clean or decommission 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 future operations. Certain environmental statutes impose strict, joint and several liability for costs required to clean 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 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, 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. In the future, Houston Electric may not be able to recover the costs incurred in restoring its transmission and distribution properties following hurricanes or other disasters through issuance of storm restoration bonds or a change in its regulated rates or otherwise, or any such recovery may not be timely granted. Therefore, Houston Electric may not be able to restore any loss of, or damage to, any of its transmission and distribution properties without negative impact on its results of operations, financial condition and cash flows.

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

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

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

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

ruptures, fires and explosions; and

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

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 is not fully insured against all risks inherent in its business. These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property, plant and equipment and pollution or other environmental damage. These risks may also result in curtailment or suspension of Enable’s operations. A natural disaster or other hazard affecting the areas in which Enable operates could have a material adverse effect on Enable’s operations. Enable does not have business interruption insurance coverage for all of its operations. Insurance coverage may not be available in the future at current costs or on commercially reasonable terms, and the insurance proceeds received for any loss of, or any damage to, any of Enable’s facilities may not be sufficient to restore the loss or damage without negative impact on its results of operations and its ability to make cash distributions.


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We, Houston Electric and CERC could incur liabilities associated with businesses and assets that we have transferred to others.

Under some circumstances, we, Houston Electric and CERC could incur liabilities associated with assets and businesses we, Houston Electric and CERC no longer own. 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 CenterPoint Energy entities. Such indemnities have applied in cases such as the litigation arising out of sales of natural gas in California and other markets (the last remaining case involving CenterPoint Energy is now on appeal, following the district court’s summary judgment in favor of CES, a subsidiary of CERC Corp.) and various asbestos and other environmental matters that arise from time to time. GenOn has publicly disclosed that it may be unable to continue as a going concern and is exploring various options, including negotiations with creditors and lessors, refinancing, potential sale of assets, as well as the possibility of filing for protection under Chapter 11 of the U.S. Bankruptcy Code. If any of the indemnifying entities were unable to meet their indemnity obligations or satisfy a liability that has been assumed or if claims in one or more of these lawsuits were successfully asserted against us, we, Houston Electric or CERC could incur liability and be responsible for satisfying the liability.

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 we would assume and agree to indemnify Texas Genco against, liabilities that Texas Genco originally assumed in connection with its organization to the extent, and only to the extent, that such liabilities are covered by certain insurance policies held by us, and in certain of the asbestos lawsuits we have agreed to continue to defend such claims to the extent they are covered by insurance maintained by us, subject to reimbursement of the costs of such defense by an NRG affiliate.

Cyber-attacks, physical security breaches, acts of terrorism or other disruptions could adversely impact our or Enable’s 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 and facilities used to (i) manage operations and other business processes and (ii) protect sensitive information maintained in the normal course of business. The operation of our electric transmission and distribution system is dependent on not only physical interconnection of our facilities but also on communications among the various components of our system. Such reliance on information and communication between and among those components has increased since deployment of smart meters and the intelligent grid.  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 phenomena, 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 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. Neither we nor Enable is fully insured against all cyber-security risks, any of which could have a material adverse effect on either our, or Enable’s, results of operations, financial condition and cash flows.

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

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

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

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

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

operator error or failure of equipment or processes;

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

labor disputes;

information technology or financial system failures that impair our information technology infrastructure, reporting systems or disrupt normal business operations;

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

catastrophic events such as fires, earthquakes, explosions, leaks, floods, droughts, hurricanes, terrorism, pandemic health events or other similar occurrences.

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

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

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

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

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

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

Regulatory agencies have from time to time considered adopting legislation, including modification of existing laws and regulations, to reduce GHGs, and there continues to be a wide-ranging policy and regulatory debate, both nationally and

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internationally, regarding the potential impact of GHGs and possible means for their regulation.  Following a finding by the EPA that certain GHGs represent an endangerment to human health, the EPA adopted two sets of rules regulating GHG emissions under the Clean Air Act, one that requires a reduction in emissions of GHGs from motor vehicles and another that regulates emissions of GHGs from certain large stationary sources. The EPA has also expanded its existing GHG emissions reporting requirements. These permitting and reporting requirements could lead to further regulation of GHGs by the EPA. As a distributor and transporter of natural gas, or a consumer of natural gas in its pipeline and gathering businesses, CERC’s or Enable’s revenues, operating costs and capital requirements, as applicable, could be adversely affected as a result of any regulatory action that would require installation of new control technologies or a modification of its operations or would have the effect of reducing the consumption of natural gas.  Our electric transmission and distribution business, in contrast to some electric utilities, does not generate electricity and thus is not directly exposed to the risk of high capital costs and regulatory uncertainties that face electric utilities that burn fossil fuels to generate electricity.  Nevertheless, Houston Electric’s revenues could be adversely affected to the extent any resulting regulatory action has the effect of reducing consumption of electricity by ultimate consumers within its 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 result in more frequent and more severe weather events which could adversely affect the results of operations of our businesses.

To the extent climate changes occur, our businesses may be adversely impacted, though we believe any such impacts are likely to occur very gradually and hence would be difficult to quantify with specificity.  To the extent global climate change results in warmer temperatures in our service territories, financial results from our natural gas distribution businesses could be adversely affected through lower gas sales, and Enable’s natural gas gathering, processing and transportation and crude oil gathering businesses could experience lower revenues. Another possible result of climate change is more frequent and more severe weather events, such as hurricanes or tornadoes.  Since many of our facilities are located along or near the Gulf Coast, increased or more severe hurricanes or tornadoes could increase our costs to repair damaged facilities and restore service to our customers.  When we cannot deliver 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.

We may be negatively impacted by changes in federal income tax policy.
 
The Executive and Legislative Branches of the United States Federal government have made public statements in support of comprehensive tax reform plans, including significant changes to corporate income tax laws. We are currently unable to predict whether these reform discussions will result in any significant changes to existing tax laws, or if any such changes would have a cumulative positive or negative impact on us or our regulatory activities.  It is possible that changes in the United States federal income tax laws could have an adverse effect on our or Enable’s results of operations, financial condition, and cash flows.

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

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


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Recent regulatory proposals from PHMSA would expand the scope of its safety, reporting and recordkeeping requirements for both natural gas and hazardous liquids (including crude oil and NGLs) pipelines, as well as underground natural gas storage facilities. These proposals, if finalized, would impose additional costs on us and Enable.

In March 2016, PHMSA issued a notice of proposed rulemaking detailing proposed revisions to the safety standards applicable to natural gas transmission and gathering pipelines. The proposed rules include significant modifications which, if adopted, will result in significant operational and integrity management changes. These include requiring reconfirmation of the Maximum Allowable Operating Pressures in pipelines without reliable records, creating new material verification procedures, adding a new moderate consequence area, and tightening repair criteria for pipelines in both high and moderate consequence areas. Other modifications include adding record-keeping and data collection obligations, and new requirements for monitoring gas quality and managing corrosion. The proposed rules also would expand the scope of gas gathering lines subject to PHMSA regulation, including imposing minimum safety standards on certain larger, currently exempt, gathering lines, while subjecting all gathering-line operators to recordkeeping and annual reporting requirements from which they are currently exempt. Other proposed changes, such as the modification to the definition of a transmission line, some record-keeping requirements, and some material verification obligations also may impact distribution pipelines although PHMSA states that such far-reaching applicability is not its intent. PHMSA is currently reviewing thousands of public comments submitted in July 2016. Because the impact of these proposed rules remains uncertain, we are still monitoring and evaluating the effect of these proposed requirements on operations.

PHMSA also issued a similar notice of proposed rulemaking for hazardous liquid pipelines in October 2015. Both of these notices of proposed rulemaking would require inspections of pipeline areas affected by severe weather, natural disasters or similar events. In addition, the proposed hazardous liquid rule would extend PHMSA reporting requirements to all gathering lines, require periodic inline inspections of pipelines outside of high consequence areas, require use of leak detection systems on all hazardous liquid pipelines, modify applicable repair criteria and set a timeline for pipelines subject to integrity management requirements to be capable of accommodating inline inspection tools. PHMSA issued the final rule for hazardous liquid pipelines on January 13, 2017, but the rule’s eventual implementation and effectiveness are uncertain as a result of a January 20, 2017 regulatory freeze. We will continue to monitor the status of this rulemaking and the effect of these proposed requirements on operations.

On December 14, 2016, PHMSA announced an interim final rule to impose industry-developed recommendations as enforceable safety standards for downhole (underground) equipment, including wells, wellbore tubing, and casing, at both interstate and intrastate underground natural gas storage facilities. This rule went into effect on January 18, 2017, with a compliance deadline of January 18, 2018. Both CERC and Enable own and operate underground storage facilities that will be subject to this rule’s provisions, which include procedures and practices for operations, maintenance, threat identification, monitoring, assessment, site security, emergency response and preparedness, training and recordkeeping. States may also impose more stringent standards on intrastate storage facilities. CERC and Enable continue to assess the potential impact of this newly announced rule.

Although many of CERC’s and Enable’s pipelines fall within a class that is currently not subject to the requirements in PHMSA’s recent proposals, they may nonetheless incur significant cost and liabilities associated with repair, remediation, prevention or mitigation measures associated with their non-exempt pipelines, which are subject to existing requirements. Work associated with PHMSA requirements is part of CERC’s and Enable’s normal integrity management program and neither expect to incur any extraordinary costs during 2017 to complete the testing required by existing DOT regulations and their state counterparts. CERC and Enable have not estimated the costs for any repair, remediation, preventive or mitigation actions that may be determined to be necessary as a result of the testing program, which could be substantial, or any lost cash flows resulting from shutting down their pipelines during the pendency of such repairs. Should CERC or Enable fail to comply with DOT or comparable state regulations, they could be subject to penalties and fines.

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

CenterPoint Energy has risks associated with aging infrastructure assets.  The age of certain of our assets may result in a need for replacement, or higher level of maintenance costs as a result of our risk based federal and state compliant integrity management programs.  Failure to achieve timely recovery of these expenses could adversely impact revenues and could result in increased capital expenditures or expenses.

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

Several of our businesses have entered into and have in place collective bargaining agreements with different labor unions. There are seven separate bargaining units in CenterPoint Energy, each with a unique collective bargaining agreement.  In 2016, Houston Electric entered into a renegotiated collective bargaining agreement with the IBEW Local 66, which is scheduled to expire in 2020, and CERC entered into two renegotiated collective bargaining agreements with Professional Employees

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International Union Local 12, which are scheduled to expire in 2021. Two collective bargaining agreements with United Steelworkers Local 227 and United Steelworkers Local 13-1 are scheduled to expire in June and July of 2017, respectively. The collective bargaining agreements with Gas Workers Union, Local 340 and the IBEW Local 949 are scheduled to expire in April and December of 2020, respectively. Any failure to reach an agreement on new labor contracts or to negotiate these labor contracts might result in strikes, boycotts or other labor disruptions. These potential labor disruptions could have a material adverse effect on our businesses, results of operations and/or cash flows. Labor disruptions, strikes or significant negotiated wage and benefit increases, whether due to union activities, employee turnover or otherwise, could have a material adverse effect on our businesses, results of operations and/or cash flows.

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

We operate in businesses that require sophisticated data collection, processing systems, software and other technology. Some of the technologies supporting the industries we serve are changing rapidly. We expect that new technologies will emerge or grow that may be superior to, or may not be compatible with, some of our existing technologies, and may require us to make significant expenditures so that we can continue to provide cost-effective and reliable methods of energy delivery. Among such technological advances are distributed generation resources (e.g., rooftop solar), 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, certain customers may choose to meet their own energy needs and subsequently decrease usage of our systems and services.

Our future success will depend, in part, on our ability to anticipate and adapt to these technological changes in a cost-effective manner and to offer, on a timely basis, reliable services that meet customer demands and evolving industry standards. If we fail to adapt successfully to any technological change or obsolescence, or fail to obtain access to important technologies or incur significant expenditures in adapting to technological change, our businesses, operating results, financial condition and cash flows could be materially and adversely affected.

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

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

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

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

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

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

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

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

For example, the success of CERC’s acquisitions of Continuum and AEM will depend, in part, on its ability to realize the expected benefits, including operating efficiencies, cost savings and customer retention, from integrating Continuum and AEM with its existing energy services business. The integration process could be costly and time consuming and may result in the following challenges, among others:

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

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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 valuable employees or third-party relationships.

Even with the successful integration of the businesses, CERC may not achieve the expected results. CERC anticipates that its acquisitions of Continuum and AEM will be accretive to earnings in 2017. Any of the factors addressed above could decrease or delay the projected accretive effect of the transaction. Failure to fully realize the expected benefits could adversely affect CERC’s results of operations, financial condition and cash flows.

In February 2016, we announced that we were exploring the use of a REIT business model for all or part of our utility businesses. We have completed our evaluation and have decided not to pursue forming a REIT structure for our utility business or any part thereof at this time. We also announced that we were evaluating strategic alternatives for our investment in Enable, including a sale or spin-off qualifying under Section 355 of the U.S. Internal Revenue Code, and we continue to evaluate our alternatives, including retaining our investment. There can be no assurances that these evaluations will result in any specific action, and we do not intend to disclose further developments on these initiatives unless and until our board of directors approves a specific action or as otherwise required.

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

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

Our bylaws designate the United States District Court for the Southern District of Texas or, if such court lacks jurisdiction, the state district court of Harris County, Texas as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our shareholders, which could limit our shareholders’ flexibility in obtaining a judicial forum for disputes with us or our directors, officers or employees.

Our bylaws provide that, unless we consent in writing to the selection of an alternative forum, the United States District Court for the Southern District of Texas or, if such court lacks jurisdiction, the state district court of Harris County, Texas will be the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action asserting a claim of breach of a fiduciary duty owed by any director, officer or other employee of ours to us or our shareholders, (iii) any action asserting a claim against us or any director, officer or other employee of ours pursuant to any provision of our articles of incorporation or bylaws (as either may be amended from time to time) or the Texas Business Organizations Code, and (iv) any action asserting a claim against us or any director, officer or other employee of ours governed by the internal affairs doctrine. These exclusive forum provisions may limit a shareholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers or other employees or agents, which may discourage such lawsuits against us and our directors, officers, employees or agents. Alternatively, if a court were to find these provisions of our bylaws inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business and financial condition.

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

We are subject to numerous legal proceedings, the most significant of which are summarized in Note14 of the consolidated financial statements. Litigation is subject to many uncertainties, and we cannot predict the outcome of individual 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 reserves and may have a material adverse effect on our financial results.


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We are exposed to risks related to reduction in energy consumption due to factors including unfavorable economic conditions in our service territories, energy efficiency initiatives and use of alternative technologies.

Our businesses are affected by reduction in energy consumption due to factors including economic climate in our service territories, energy efficiency initiatives and use of alternative technologies, which could impact our ability to grow our customer base and our rate of growth. Declines in demand for electricity as a result of economic downturns in our 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 is 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 our results of operations and cash flows could result in future material impairment charges to write-down the carrying value of certain assets, including goodwill, to their respective fair values.

For example, our electric business is largely concentrated in Houston, Texas, where a higher percentage of employment is tied to the energy sector relative to other regions of the country. Given the significant decline in energy and commodity prices in 2015 and 2016, and resulting low commodity prices which we expect to continue in 2017, the rate of growth in employment in Houston has declined. In the event economic conditions further decline, the rate of growth in Houston and the other areas in which we operate may also deteriorate. Increases in customer defaults or delays in payment due to liquidity constraints could negatively impact our cash flows and financial condition.

Growth in customer accounts and growth of customer usage each directly influence demand for 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.

Certain regulatory and legislative bodies have introduced or are considering requirements and/or incentives to reduce energy consumption by certain dates. Additionally, technological advances driven by federal laws mandating new levels of energy efficiency in end-use electric devices or other improvements in or applications of technology could lead to declines in per capita energy consumption.

Some or all of these factors, could result in a lack of growth or decline in customer demand for electricity or number of customers, and may result in our failure to fully realize anticipated benefits from significant capital investments and expenditures which could have a material adverse effect on their financial position, results of operations and cash flows.

Furthermore, we currently have energy efficiency riders in place to recover the cost of energy efficiency programs. Should we be required to invest in conservation measures that result in reduced sales from effective conservation, regulatory lag in adjusting rates for the impact of these measures could have a negative financial impact.

If we fail to maintain an effective system of internal controls, our ability to accurately report our financial condition, results of operations or cash flows or prevent fraud may be adversely affected. As a result, investors could lose confidence in our financial reporting, which could impact our businesses and the trading price of our securities.
 
Effective internal controls are necessary for us to provide reliable financial reports, effectively prevent fraud and operate successfully as a public company. If our efforts to maintain internal controls are not successful, we are unable to maintain adequate controls over our financial reporting and processes in the future or we are unable to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002, our operating results could be harmed or we may fail to meet our reporting obligations. Ineffective internal controls also could cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our securities.

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.

39




Item 1B.
Unresolved Staff Comments

None.

Item 2.
Properties

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

For information regarding the properties of our Electric Transmission & Distribution business 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

For information regarding the properties of our Natural Gas Distribution business 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

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

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

Other Operations

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

Item 3.
Legal Proceedings

For a discussion of material legal and regulatory proceedings affecting us, 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 15(d) to our consolidated financial statements, which information is incorporated herein by reference.

Item 4.
Mine Safety Disclosures

Not applicable.


40



PART II

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

As of February 10, 2017 , our common stock was held by approximately 32,130 shareholders of record. Our common stock is listed on the NYSE and Chicago Stock Exchange and is traded under the symbol “CNP.”

The following table sets forth the high and low closing prices of the common stock of CenterPoint Energy on the NYSE composite tape during the periods indicated, as reported by Bloomberg, and the cash dividends declared in these periods.
 
  Market Price
 
Dividend
Declared
 
High
 
Low
 
Per Share
2016
 
 
 
 
 
First Quarter
 
 
 
 
$
0.2575

January 20
 
 
$
16.90

 
 
March 29
$
21.25

 
 
 
 
Second Quarter
 
 
 
 
$
0.2575

April 5
 
 
$
20.51

 
 
June 29
$
24.00

 
 
 
 
Third Quarter
 
 
 
 
$
0.2575

July 22
$
24.69

 
 
 
 
August 16
 
 
$
22.13

 
 
Fourth Quarter
 
 
 
 
$
0.2575

October 11
 
 
$
21.84

 
 
December 22
$
24.84

 
 
 
 
 
 
 
 
 
 
2015
 
 
 
 
 
First Quarter
 
 
 
 
$
0.2475

January 2
$
23.63

 
 
 
 
March 31
 
 
$
20.41

 
 
Second Quarter
 
 
 
 
$
0.2475

April 15
$
21.31

 
 
 
 
June 30
 
 
$
19.03

 
 
Third Quarter
 
 
 
 
$
0.2475

August 14
$
19.92

 
 
 
 
September 29
 
 
$
17.53

 
 
Fourth Quarter
 
 
 
 
$
0.2475

October 22
$
19.13

 
 
 
 
December 10
 
 
$
16.14

 
 

The closing market price of our common stock on December 31, 2016 was $24.64 per share.

The amount of future cash dividends will be subject to determination based upon our results of operations and financial condition, our future business prospects, any applicable contractual restrictions and other factors that our board of directors considers relevant and will be declared at the discretion of the board of directors.

On January 5, 2017 , our board of directors declared a regular quarterly cash dividend of $0.2675  per share, payable on March 10, 2017 to shareholders of record on February 16, 2017 .


41



Repurchases of Equity Securities

During the quarter ended December 31, 2016 , none of our equity securities registered pursuant to Section 12 of the Securities Exchange Act of 1934 were purchased by or on behalf of us or any of our “affiliated purchasers,” as defined in Rule 10b-18(a)(3) under the Securities Exchange Act of 1934.

Item 6.         Selected Financial Data

The following table presents selected financial data with respect to our consolidated financial condition and consolidated results of operations and should be read in conjunction with our consolidated financial statements and the related notes in Item 8 of this report.
 
Year Ended December 31,
 
2016
 
2015
 
2014
 
2013
 
2012
 
(in millions, except per share amounts)
Revenues
$
7,528

 
$
7,386

 
$
9,226

 
$
8,106

 
$
7,452

Equity in earnings (losses) of unconsolidated affiliates
208

 
(1,663
)
(1)
308

 
188

 
31

Net income (loss)
$
432

 
$
(692
)
 
$
611

 
$
311


$
417

 
 
 
 
 
 
 
 
 
 
Basic earnings (loss) per common share
$
1.00

 
$
(1.61
)
 
$
1.42

 
$
0.73


$
0.98

 
 
 
 
 
 
 
 
 
 
Diluted earnings (loss) per common share
$
1.00

 
$
(1.61
)
 
$
1.42

 
$
0.72


$
0.97

 
 
 
 
 
 
 
 
 
 
Cash dividends declared per common share
$
1.03

 
$
0.99

 
$
0.95

 
$
0.83

 
$
0.81

Dividend payout ratio
103
%
 
n/a

 
67
%

114
%

83
%
Return on average common equity
12
%
 
(17
)%
 
14
%
 
7
%
 
10
%
Ratio of earnings to fixed charges
2.74

 
2.67

 
2.79

 
2.42

 
2.29

At year-end:
 
 
 
 
 
 
 
 
 
Book value per common share
$
8.04

 
$
8.05

 
$
10.58

 
$
10.09

 
$
10.09

Market price per common share
24.64

 
18.36

 
23.43

 
23.18

 
19.25

Market price as a percent of book value
306
%
 
228
 %
 
221
%
 
230
%
 
191
%
Limited partner interests owned in Enable
54.1
%
 
55.4
 %
 
55.4
%
 
58.3
%
 
n/a
Total assets (2)
$
21,829

 
$
21,290

 
$
23,150

 
$
21,816

 
$
22,806

Short-term borrowings
35

 
40

 
53

 
43

 
38

Securitization bonds, including current maturities (2)
2,278

 
2,667

 
3,037

 
3,388

 
3,832

Other long-term debt, including current maturities (2)
6,279

 
6,063

 
5,717

 
4,873

 
5,861

Capitalization:
 
 
 
 
 
 
 
 
 
Common stock equity
29
%
 
28
 %
 
34
%
 
34
%
 
31
%
Long-term debt, including current maturities
71
%
 
72
 %
 
66
%
 
66
%
 
69
%
Capitalization, excluding securitization bonds:
 
 
 
 
 
 
 
 
 
Common stock equity
36
%
 
36
 %
 
44
%
 
47
%
 
42
%
Long-term debt, excluding securitization bonds, and including current maturities
64
%
 
64
 %
 
56
%
 
53
%
 
58
%
Capital expenditures
$
1,406

 
$
1,575

 
$
1,402

 
$
1,272

 
$
1,188


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

(2)
Amounts for 2012 to 2015 have been restated to reflect adoption of ASU 2015-03.


42



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

The following discussion and analysis should be read in combination with our consolidated financial statements included in Item 8 herein.

OVERVIEW

Background

We are a public utility holding company. Our operating subsidiaries own and operate electric transmission and distribution and natural gas distribution facilities, supply natural gas to commercial and industrial customers and electric and natural gas utilities and own interests in Enable as described below. Our indirect, wholly-owned subsidiaries include:

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

CERC Corp., which owns and operates natural gas distribution systems in six states; and

CES, which 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 31 states.

As of December 31, 2016 , we also owned an aggregate of 14,520,000 Series A Preferred Units in Enable, which owns, operates and develops natural gas and crude oil infrastructure assets, and CERC Corp. owned approximately 54.1% of the limited partner interests in Enable.

Business Segments

In this Management’s Discussion and Analysis, we discuss our results from continuing operations on a consolidated basis and individually for each of our business segments. We also discuss our liquidity, capital resources and critical accounting policies. We are first and foremost an energy delivery company and it is our intention to remain focused on these segments of the energy business. The results of our business operations are significantly impacted by weather, customer growth, economic conditions, cost management, competition, rate proceedings before regulatory agencies and other actions of the various regulatory agencies to whose jurisdiction we are subject. Our electric transmission and distribution services are subject to rate regulation and are reported in the Electric Transmission & Distribution business segment, as are impacts of generation-related stranded costs and other true-up balances recoverable by the regulated electric utility. For further information about our Electric Transmission & Distribution business segment, see “Business — Our Business — Electric Transmission & Distribution” in Item 1 of Part I of this report. Our natural gas distribution services are also subject to rate regulation and are reported in the Natural Gas Distribution business segment. For further information about our Natural Gas Distribution business segment, see “Business — Our Business — Natural Gas Distribution” in Item 1 of Part I of this report. Our Energy Services business segment includes non-rate regulated natural gas sales to, and transportation and storage services, for commercial and industrial customers. For further information about our Energy Services business segment, see “Business — Our Business — Energy Services” in Item 1 of Part I of this report. The results of our Midstream Investments business segment are dependent upon the results of Enable, which are driven primarily by the volume of natural gas, NGLs and crude oil that Enable gathers, processes and transports across its systems and other factors as discussed below under “— Factors Influencing Our Midstream Investments Segment.” Our Other Operations business segment includes office buildings and other real estate used in our business operations and other corporate operations which support all of our business operations.

EXECUTIVE SUMMARY

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

We are an energy delivery company. The majority of our revenues are generated from the sale of natural gas and the transmission and delivery of electricity by our subsidiaries. We do 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 from our business segments. Within these broader financial measures, we monitor margins, operation and maintenance expense,

43



interest expense, capital spending and working capital requirements. In addition to these financial measures, we also monitor a number of variables that management considers important to the operation of our business segments, including the number of customers, throughput, use per customer, commodity prices and heating and cooling degree days. We also monitor system reliability, safety factors and customer satisfaction to gauge our performance.

To the extent adverse economic conditions affect our suppliers and customers, results from our energy delivery businesses may suffer. For example, our electric 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. 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. Given the significant decline in energy and commodity prices in 2015, the rate of growth in employment in Houston, which had been greater than the national average, has declined and is now more in line with the national average. We expect this trend to continue in the foreseeable future. Also, adverse economic conditions, coupled with concerns for protecting the environment, may cause consumers to use less energy or avoid expansions of their facilities, resulting in less demand for our services. Reviewing recent years, year-over-year meter growth for Houston Electric hit a high in 2014 at 2.4%.  This growth slowed to 2.1% for 2015, largely as a result of the performance of the energy sector.  With some stabilization of the energy section in 2016, Houston Electric meter growth experienced an uptick to 2.3%.  We anticipate that this growth will continue at roughly 2%, in line with recent years.

Performance of our Electric Transmission & Distribution and Natural Gas Distribution business segments is significantly influenced by the number of customers and energy usage per customer. Weather conditions can have a significant impact on energy usage, and we compare our results on a weather adjusted basis. In 2016, our Houston service area experienced above normal warmth with episodes of flooding. Houston’s average temperature of 71.4 degrees Fahrenheit was the seventh highest (record 2012) going back to 1889. In 2015, our Houston service area experienced some of the mildest temperatures on record during November and December. Every state in which we distribute natural gas had a warmer than normal winter in 2016 and 2015. Both the TDU and NGD have utilized weather hedges in the past to help reduce the impact of mild weather on its financial results.  However, only the TDU entered a weather hedge for the 2015-2016 and 2016-2017 heating seasons. NGD did not enter a weather hedge for the last two winter seasons as a result of NGD’s Minnesota division implementing a full decoupling pilot in July 2015.  We also have various rate mechanisms in place that help to mitigate the impact of abnormal weather on our financial results.  Our long-term national trends indicate customers have reduced their energy consumption, and reduced consumption can adversely affect our results. However, due to more affordable energy prices and continued economic improvement in the areas we serve, the trend toward lower usage has slowed in some of the areas we serve. In Minnesota and Arkansas, rate adjustment mechanisms counter the impact of declining usage from energy efficiency improvements. In addition, in many of our service areas, particularly in the Houston area and Minnesota, we have benefited from growth in the number of customers. This growth also tends to mitigate the effects of reduced consumption.  We anticipate that this trend will continue as the regions’ economies continue to grow.  The profitability of our businesses is influenced significantly by the regulatory treatment we receive from the various state and local regulators who set our electric and natural gas distribution rates.

Our Energy Services business segment contracts with customers for transportation, storage and sales of natural gas on an unregulated basis.  Its operations serve customers primarily in the central United States.  The segment benefits from favorable price differentials, either on a geographic basis or on a seasonal basis. While this business utilizes financial derivatives to mitigate the effects of price movements, it does not enter into risk management contracts for speculative purposes and maintains a low VaR to avoid significant financial exposures.  In 2016, CES acquired Continuum, which included approximately 13,000 customers and 175 Bcf of gas sales.  The customer base was comprised of a mix similar to our existing business.  This acquisition helped drive the overall operating income increase for Energy Services in 2016 as compared to 2015, excluding mark-to-market accounting for derivatives. In 2015 and 2014, Energy Services exhibited strong commercial and industrial customer results while capitalizing on asset optimization opportunities created by basis volatility. Extreme cold weather in 2014 also increased throughput and margin from our weather sensitive customers. In January 2017, CES acquired AEM. For more information regarding this acquisition, see Note 19 to our consolidated financial statements.

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, companies like us 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.

44




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

We expect to make contributions to our pension plans aggregating approximately $46 million in 2017 but may need to make larger contributions in subsequent years. Consistent with the regulatory treatment of such costs, we can defer the amount of pension expense that differs from the level of pension expense included in our base rates for our Electric Transmission & Distribution business segment and Natural Gas Distribution business segment in Texas.

Factors Influencing Our Midstream Investments Segment
The results of our Midstream Investments segment are dependent upon the results of Enable, which are driven primarily by the volume of natural gas, NGLs 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, discussed below. 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 them. 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. In early 2016, natural gas and crude oil prices dropped to their lowest levels in over 10 years. Both natural gas and crude oil prices increased moderately in the second half of 2016. If current commodity prices levels persist, or if commodity price levels decline, Enable’s future volumes and cash flows may be negatively impacted. Commodity prices impact the drilling and production of natural gas and crude oil in the areas served by Enable’s systems, and the volumes on Enable’s systems are negatively impacted if producers decrease drilling and production in those areas served. Both Enable’s gathering and processing segment and its transportation and storage segment can be impacted by drilling and production. Enable’s gathering and processing segment primarily serves producers, and many producers utilize the services provided by its transportation and storage segment. A decrease in volumes will decrease cash flows from Enable’s systems. In addition, Enable’s processing arrangements expose it to commodity price fluctuations. Enable has attempted to mitigate the impact of commodity prices on its business by entering into hedges, focusing on contracting fee-based business and converting existing commodity-based contracts to fee-based contracts.

Despite recent low commodity prices, Enable’s long-term view is that natural gas and crude oil production in the U.S. will increase. Over the past several years, there has been a fundamental shift in U.S. natural gas and crude oil production towards tight gas formations and shale plays. Advancements in technology have allowed producers to efficiently extract natural gas and crude oil from these formations and plays. As a result, the proven reserves of natural gas and crude oil in the U.S. have significantly increased and the price of natural gas and crude oil has decreased compared to historical periods.

Natural gas continues to be a critical component of energy demand in the U.S. Over the long term, Enable’s management believes that the prospects for continued natural gas demand are favorable and will be driven by population and economic growth, as well as the continued displacement of coal-fired power plants by natural gas-fired power plants due to the price of natural gas and stricter government environmental regulations on the mining and burning of coal. The EIA projects that the majority of domestic consumption growth will be in the electric power, industrial and liquefaction for export sectors where the aggregate natural gas demand of these sectors is expected to grow from approximately 17.8 trillion cubic feet of natural gas in 2016 to approximately 21.0 trillion cubic feet of natural in 2040. Enable’s management believes that increasing consumption of natural gas over the long term in these sectors will continue to drive demand for Enable’s natural gas gathering, processing, transportation and storage services.

Enable may access the capital markets to fund its expansion capital expenditures. Historically, unit prices of midstream master limited partnerships have experienced periods of volatility. In addition, because Enable’s common units are yield-based securities, rising market interest rates could impact the relative attractiveness of Enable’s common units to investors. Further, fluctuations in energy and commodity prices can create volatility in Enable’s common unit prices, which could impact investor appetite for its common units. Volatility in energy and commodity prices, as well as other macro-economic factors could impact the relative

45



attractiveness of Enable’s debt securities to investors. As a result of capital market volatility, Enable may be unable to issue equity securities or debt on satisfactory terms, or at all, which may limit its ability to expand its operations or make future acquisitions.

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

Enable relies on certain key natural gas producer customers for a significant portion of its natural gas and NGLs supply. For the year ended December 31, 2016, Enable’s top ten natural gas producer customers accounted for approximately 66% of its gathered volumes. These customers include affiliates of Continental, Vine, GeoSouthern, XTO Energy, Apache, Tapstone, Chesapeake, BP Energy Company, Covey Park and Marathon. Further, Enable relies on certain key utilities and producers for a significant portion of its transportation and storage demand. For the year ended December 31, 2016, Enable’s top transportation and storage customers by revenue were affiliates of CenterPoint Energy, Spire, XTO Energy, American Electric Power Company, OGE, Continental, Chesapeake, Midcoast Energy Partners, EOG Resources and Entergy.

Enable is exposed to certain credit risks relating to its ongoing business operations. Credit risk includes the risk that counterparties that owe Enable money or energy will breach their obligations. If the counterparties to these arrangements fail to perform, Enable may be forced to enter into alternative arrangements. In that event, Enable’s financial results could be adversely affected, and Enable could incur losses. Enable examines the creditworthiness of third-party customers to whom it extends credit and manages its exposure to credit risk through credit analysis, credit approval, credit limits and monitoring procedures, and for certain transactions, Enable may request letters of credit, prepayments or guarantees or seek to renegotiate its contract to reduce credit exposure.

Significant Events

Brazos Valley Connection Project. Houston Electric began construction on the Brazos Valley Connection in February 2017. For further details on the Brazos Valley Connection Project, see “—Liquidity and Capital Resources —Regulatory Matters —Houston Electric” below.

Regulatory Proceedings. For details related to our pending and completed regulatory proceedings in 2016, see “—Liquidity and Capital Resources —Regulatory Matters” below.

Series A Preferred Units. In February 2016, we purchased $363 million of Series A Preferred Units from Enable. For further information related to the purchase, see Note 10 to our consolidated financial statements.

Credit Facilities.   For details related to refinancing of our credit facilities and increasing our commercial paper programs, see “—Liquidity and Capital Resources —Other Matters —Credit Facilities” below.

Debt Transactions. In 2016, we and CERC retired a combined $625 million aggregate principal amount of senior notes, Houston Electric issued $600 million aggregate principal amount of general mortgage bonds, and as of February 10, 2017, Houston Electric had issued $300 million aggregate principal amount of general mortgage bonds in 2017. For further information about our 2016 and 2017 debt transactions, see Note 13 to our consolidated financial statements.

Charter Merger. In May 2016, Charter’s merger with TWC closed. For further information regarding the Charter merger and its impact on ZENS, see Note 11 to our consolidated financial statements.

Continuum Acquisition. In April 2016, CES closed the previously announced agreement to acquire the energy services business of Continuum. For more information regarding the acquisition, see Note 4 to our consolidated financial statements.

AEM Acquisition. In January 2017, CES closed the previously announced agreement to acquire AEM. For more information regarding this acquisition, see Note 19 to our consolidated financial statements.


46



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 including:

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

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

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

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

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

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

changes in tax status;

access to debt and equity capital; and

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

industrial, commercial and residential growth in our service territories and changes in market demand, including the effects of energy efficiency measures and demographic patterns;

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

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

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

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

tax reform and legislation;

our ability to mitigate weather impacts through normalization or rate mechanisms, and the effectiveness of such mechanisms;

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

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

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

the impact of unplanned facility outages;

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

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

our ability to control operation and maintenance costs;

47




actions by credit rating agencies;

the sufficiency of our insurance coverage, including availability, cost, coverage and terms;

the investment performance of our pension and postretirement benefit plans;

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

changes in interest rates or rates of inflation;

inability of various counterparties to meet their obligations to us;

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

effectiveness of our risk management activities;

timely and appropriate regulatory actions allowing securitization or other recovery of costs associated with any future hurricanes or natural disasters;

our potential business strategies and strategic initiatives, including restructurings, joint ventures and acquisitions or dispositions of assets or businesses, which we cannot assure you will be completed or will have the anticipated benefits to us;

acquisition and merger activities involving us or our competitors;

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

the ability of GenOn (formerly known as RRI Energy, Inc., Reliant Energy and RRI), a wholly-owned subsidiary of NRG, and its subsidiaries to satisfy their obligations to us, including indemnity obligations;

the outcome of litigation;

the ability of REPs, including REP affiliates of NRG and Energy Future Holdings, to satisfy their obligations to us and our subsidiaries;

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

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

the effective tax rates;

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

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


48



CONSOLIDATED RESULTS OF OPERATIONS
 
Year Ended December 31,
 
2016
 
2015
 
2014
 
(in millions, except per share amounts)
Revenues
$
7,528

 
$
7,386

 
$
9,226

Expenses
6,569

 
6,453

 
8,291

Operating Income
959

 
933

 
935

Gain (Loss) on Marketable Securities
326

 
(93
)
 
163

Gain (Loss) on Indexed Debt Securities
(413
)
 
74

 
(86
)
Interest and Other Finance Charges
(338
)
 
(352
)
 
(353
)
Interest on Securitization Bonds
(91
)
 
(105
)
 
(118
)
Equity in Earnings (Losses) of Unconsolidated Affiliates
208

 
(1,633
)
 
308

Other Income, net
35

 
46

 
36

Income (Loss) Before Income Taxes
686

 
(1,130
)
 
885

Income Tax Expense (Benefit)
254

 
(438
)
 
274

Net Income (Loss)
$
432

 
$
(692
)
 
$
611

 
 
 
 
 
 
Basic Earnings (Loss) Per Share
$
1.00

 
$
(1.61
)
 
$
1.42

 
 
 
 
 
 
Diluted Earnings (Loss) Per Share
$
1.00

 
$
(1.61
)
 
$
1.42


2016 Compared to 2015

Net Income.   We reported net income of $432 million ( $1.00  per diluted share) for 2016 compared to a net loss of $692 million ( $(1.61)  per diluted share) for the same period in 2015 .

The increase in net income of $1,124 million was due to the following key factors:

a $1,841 million increase in equity earnings from our investment in Enable, as 2015 results included impairment charges of $1,846 million, discussed further in Note 10 to our consolidated financial statements;

a $419 million increase in the gain on our marketable securities;

a $26 million increase in operating income discussed below by segment;

a $22 million increase in cash distributions on Series A Preferred Units included in Other Income, net shown above;

a $14 million decrease in interest expense due to lower weighted average interest rates on outstanding debt; and

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

These increases were partially offset by:

a $692 million increase in income tax expense due to higher income before tax;

a $487 million increase in the loss on indexed debt securities related to the ZENS resulting from a loss of $117 million from the Charter merger in 2016 compared to a loss of $7 million from Verizon’s acquisition of AOL in 2015 and increased losses of $377 million in the underlying value of the indexed debt securities;

a $22 million loss on early redemption of our $300 million 6.5% senior notes otherwise due 2018 included in Other Income, net shown above;


49



a $6 million decrease in interest income due primarily to Enable’s repayment of $363 million note payable to us included in Other Income, net shown above; and

a $5 million decrease in miscellaneous other non-operating income include in Other Income, net shown above.

Income Tax Expense.  We reported an effective tax rate of 37% and 39% for the years ended December 31, 2016 and 2015, respectively. The effective tax rate of 39% is primarily due to lower earnings from the impairment of our investment in Enable. The impairment loss reduced the deferred tax liability on our investment in Enable.

2015 Compared to 2014

Net Income.   We reported a net loss of $692 million ( $(1.61)  per diluted share) for 2015 compared to net income of $611 million ( $1.42  per diluted share) for the same period in 2014 .

The decrease in net income of $1,303 million was due to the following key factors:

a $1,941 million decrease in equity earnings of unconsolidated affiliates, which included impairment charges of $1,846 million, discussed further in Note 10 to our consolidated financial statements; and

a $256 million increase in the loss on our marketable securities.

These decreases were partially offset by:

a $712 million decrease in income tax expense;

a $160 million increase in the gain on our indexed debt securities related to the ZENS resulting from a loss of $7 million from Verizon’s acquisition of AOL in 2015 and increased gains of $167 million in the underlying value of the indexed debt securities;

a $13 million decrease in interest expense related to lower outstanding balances of our Securitization Bonds;

a $9 million increase in proceeds received from the settlement of corporate-owned life insurance policies included in Other Income, net shown above; and

a $1 million increase in miscellaneous other non-operating income included in Other Income, net shown above.

Income Tax Expense.  We reported an effective tax rate of 39% and 31% for the years ended December 31, 2015 and 2014, respectively. The higher effective tax rate of 39% is primarily due to lower earnings from the impairment of our equity method investment in Enable. The impairment loss reduced the deferred tax liability on our investment in Enable. The effective tax rate of 31% for 2014 is primarily due to a $29 million tax benefit recognized upon completion of a tax basis balance sheet review and a $13 million reversal of previously accrued taxes as a result of final positions taken in the 2013 tax returns. We determined the impact of the $29 million adjustment was not material to any prior period or the year ended December 31, 2014.


50



RESULTS OF OPERATIONS BY BUSINESS SEGMENT

The following table presents operating income for each of our business segments for 2016 , 2015 and 2014 . Included in revenues are intersegment sales. We account for intersegment sales as if the sales were to third parties, that is, at current market prices.

Operating Income by Business Segment
 
Year Ended December 31,
 
2016
 
2015
 
2014
 
(in millions)
Electric Transmission & Distribution
$
628

 
$
607

 
$
595

Natural Gas Distribution
303

 
273

 
287

Energy Services
20

 
42

 
52

Other Operations
8

 
11

 
1

Total Consolidated Operating Income
$
959

 
$
933

 
$
935


Electric Transmission & Distribution

The following tables provide summary data of our Electric Transmission & Distribution business segment for 2016 , 2015 and 2014 :
 
Year Ended December 31,
 
2016
 
2015
 
2014
Revenues:
(in millions, except throughput and customer data)
TDU
$
2,507

 
$
2,364

 
$
2,279

Bond Companies
553

 
481

 
566

Total revenues
3,060

 
2,845

 
2,845

Expenses:
 

 
 

 
 

Operation and maintenance, excluding Bond Companies
1,355

 
1,300

 
1,251

Depreciation and amortization, excluding Bond Companies
384

 
340

 
327

Taxes other than income taxes
231

 
222

 
224

Bond Companies
462

 
376

 
448

Total expenses
2,432

 
2,238

 
2,250

Operating Income
$
628

 
$
607

 
$
595

Operating Income:
 
 
 

 
 
TDU
$
537

 
$
502

 
$
477

Bond Companies (1)  
91

 
105

 
118

Total segment operating income
$
628

 
$
607

 
$
595

Throughput (in GWh):
 

 
 

 
 

Residential
29,586

 
28,995

 
27,498

Total
86,829

 
84,191

 
81,839

Number of metered customers at end of period:
 

 
 

 
 

Residential
2,129,773

 
2,079,899

 
2,033,027

Total
2,403,340

 
2,348,517

 
2,299,247


(1)
Represents the amount necessary to pay interest on the securitization bonds.

2016 Compared to 2015 .   Our Electric Transmission & Distribution business segment reported operating income of $628 million for 2016 , consisting of $537 million  from the TDU and $91 million related to the Bond Companies. For 2015 , operating income totaled $607 million , consisting of $502 million from the TDU and $105 million related to the Bond Companies.


51



TDU operating income increased $35 million due to the following key factors:

customer growth of $31 million from the addition of over 54,000 customers;

higher transmission-related revenues of $82 million, partially offset by transmission costs billed by transmission providers of $55 million;

higher equity return of $17 million, primarily due to the annual true-up of transition charges correcting for under-collections that occurred during the preceding 12 months; and

rate increases of $13 million related to distribution capital investments.

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

higher depreciation, primarily because of ongoing additions to plant in service, and other taxes of $45 million;

higher operating and maintenance expenses of $3 million; and

lower right-of-way revenues of $3 million.
 
2015 Compared to 2014 .   Our Electric Transmission & Distribution business segment reported operating income of $607 million for 2015 , consisting of $502 million  from the TDU and $105 million related to the Bond Companies. For 2014 , operating income totaled $595 million , consisting of $477 million from the TDU and $118 million related to the Bond Companies.

TDU operating income increased $25 million due to the following key factors:

higher transmission-related revenues of $81 million, which were partially offset by increased transmission costs billed by transmission providers of $47 million;

customer growth of $25 million from the addition of nearly 50,000 new customers;

higher usage of $17 million, primarily due to a return to normal weather; and

rate increases of $5 million associated with distribution capital investments.

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

lower equity return of $20 million, primarily related to the annual true-up of transition charges correcting for over-collections that occurred during the preceding 12 months;

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

higher depreciation of $13 million; and

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


52



Natural Gas Distribution

The following table provides summary data of our Natural Gas Distribution business segment for 2016 , 2015 and 2014
 
Year Ended December 31,
 
2016
 
2015
 
2014
 
(in millions, except throughput and customer data)
Revenues
$
2,409

 
$
2,632

 
$
3,301

Expenses: