CenterPoint Energy - 10-Q quarterly report FY2017 Q3

CenterPoint Energy - 10-Q quarterly report FY2017 Q3

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

__________________

FORM 10-Q



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

	FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2017



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	(713) 207-1111
(Address and zip code of principal executive offices)	(Registrant’s telephone number, including area code)

_____________________________________

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



Large accelerated filer þ	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o	Emerging growth company o
		(Do not check if a smaller reporting company)

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

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

As of October 26, 2017, CenterPoint Energy, Inc. had 431,033,509 shares of common stock outstanding, excluding 166 shares held as treasury stock.

CENTERPOINT ENERGY, INC.

QUARTERLY REPORT ON FORM 10-Q

FOR THE QUARTER ENDED SEPTEMBER 30, 2017

TABLE OF CONTENTS



PART I.	FINANCIAL INFORMATION

Item 1.	Financial Statements	1

	Condensed Statements of Consolidated Income
	Three and Nine Months Ended September 30, 2017 and 2016 (unaudited)	1

	Condensed Statements of Consolidated Comprehensive Income
	Three and Nine Months Ended September 30, 2017 and 2016 (unaudited)	2

	Condensed Consolidated Balance Sheets
	September 30, 2017 and December 31, 2016 (unaudited)	3

	Condensed Statements of Consolidated Cash Flows
	Nine Months Ended September 30, 2017 and 2016 (unaudited)	5

	Notes to Unaudited Condensed Consolidated Financial Statements	6

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	28

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	43

Item 4.	Controls and Procedures	43

PART II.	OTHER INFORMATION

Item 1.	Legal Proceedings	44

Item 1A.	Risk Factors	44

Item 5.	Other Information	44

Item 6.	Exhibits	44



GLOSSARY
AEM		Atmos Energy Marketing, LLC, previously a wholly-owned subsidiary of Atmos Energy Holdings, Inc., a wholly-owned subsidiary of Atmos Energy Corporation
AMAs		Asset Management Agreements
AMS		Advanced Metering System
APSC		Arkansas Public Service Commission
ASU		Accounting Standards Update
AT&T		AT&T Inc.
AT&T Common		AT&T common stock
Bcf		Billion cubic feet
BDA		Billing Determinant Adjustment, which is a revenue stabilization mechanism used to adjust revenues impacted by declines in natural gas consumption which occurred after the most recent rate case
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
CenterPoint Energy		CenterPoint Energy, Inc., and its subsidiaries
CERC Corp.		CenterPoint Energy Resources Corp.
CERC		CERC Corp., together with its subsidiaries
CES		CenterPoint Energy Services, Inc., a wholly-owned subsidiary of CERC Corp.
Charter Common		Charter Communications, Inc. common stock
Charter merger		Merger of Charter Communications, Inc. and Time Warner Cable Inc.
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 previously owned by Continuum Energy Services, LLC
DCRF		Distribution Cost Recovery Factor
EECR		Energy Efficiency Cost Recovery
EECRF		Energy Efficiency Cost Recovery Factor
Enable		Enable Midstream Partners, LP
ERCOT		Electric Reliability Council of Texas
FASB		Financial Accounting Standards Board
Fitch		Fitch, Inc.
Form 10-Q		Quarterly Report on Form 10-Q
FRP		Formula Rate Plan
Gas Daily		Platt’s gas daily indices
GenOn		GenOn Energy, Inc.
GRIP		Gas Reliability Infrastructure Program
GWh		Gigawatt-hours
Houston Electric		CenterPoint Energy Houston Electric, LLC and its subsidiaries
IBEW		International Brotherhood of Electrical Workers
Interim Condensed Financial Statements		Condensed consolidated interim financial statements and notes
IRS		Internal Revenue Service
LIBOR		London Interbank Offered Rate
LPSC		Louisiana Public Service Commission
MGPs		Manufactured gas plants
MLP		Master Limited Partnership
MMBtu		One million British thermal units



GLOSSARY (cont.)
Moody’s		Moody’s Investors Service, Inc.
MPSC		Mississippi Public Service Commission
MPUC		Minnesota Public Utilities Commission
NECA		National Electrical Contractors Association
NGD		Natural gas distribution business
NGLs		Natural gas liquids
NRG		NRG Energy, Inc.
NYMEX		New York Mercantile Exchange
OCC		Oklahoma Corporation Commission
OGE		OGE Energy Corp.
PBRC		Performance Based Rate Change
PHMSA		U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration
PRPs		Potentially responsible parties
PUCT		Public Utility Commission of Texas
Railroad Commission		Railroad Commission of Texas
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
Securitization Bonds		Transition and system restoration bonds
Series A Preferred Units		10% Series A Fixed-to-Floating Non-Cumulative Redeemable Perpetual Preferred Units representing limited partner interests in Enable
S&P		Standard & Poor’s Ratings Services, a division of The McGraw-Hill Companies
TBD		To be determined
TCEH Corp.		Formerly Texas Competitive Electric Holdings Company LLC, predecessor to Vistra Energy Corp. whose major subsidiaries include Luminant and TXU Energy
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
TW		Time Warner Inc.
TW Common		TW common stock
TW Securities		Charter Common, Time Common and TW Common
VIE		Variable interest entity
Vistra Energy Corp.		Texas-based energy company focused on the competitive energy and power generation markets
ZENS		2.0% Zero-Premium Exchangeable Subordinated Notes due 2029
2016 Form 10-K		Annual Report on Form 10-K for the year ended December 31, 2016

iii

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.

The following are some of the factors that could cause actual results to differ from those expressed or implied by our forward-looking statements:


•	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;


•	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;


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


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

•

our or Enable’s potential business strategies and strategic initiatives, including restructurings, joint ventures and acquisitions or dispositions of assets or businesses (including a reduction of our interests in Enable, whether through our election to sell the common units we own in the public equity markets or otherwise, subject to certain limitations), which we cannot assure you will be completed or will have the anticipated benefits to us or Enable;


•	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, currently the subject of bankruptcy proceedings, to satisfy their obligations to us, including indemnity obligations;


•	the outcome of litigation;


•	the ability of REPs, including REP affiliates of NRG and Vistra Energy Corp., formerly known as TCEH Corp., to satisfy their obligations to 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 in “Risk Factors” in Item 1A of Part I of our 2016 Form 10-K, which is incorporated herein by reference, and other reports we file from time to time with the SEC.

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.

Table of Contents

PART I. FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

CONDENSED STATEMENTS OF CONSOLIDATED INCOME

(In Millions, Except Per Share Amounts)

(Unaudited)



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2017			2016			2017			2016

Revenues:
Utility revenues	$	1,233		$	1,278		$	4,001		$	4,003
Non-utility revenues	865			611			2,975			1,444
Total	2,098			1,889			6,976			5,447

Expenses:
Utility natural gas	106			99			706			663
Non-utility natural gas	832			584			2,843			1,368
Operation and maintenance	519			505			1,614			1,539
Depreciation and amortization	269			324			749			873
Taxes other than income taxes	93			93			288			288
Total	1,819			1,605			6,200			4,731
Operating Income	279			284			776			716

Other Income (Expense):
Gain on marketable securities	37			77			104			187
Loss on indexed debt securities	(36		)	(72		)	(59		)	(258		)
Interest and other finance charges	(80		)	(83		)	(235		)	(256		)
Interest on securitization bonds	(18		)	(23		)	(58		)	(70		)
Equity in earnings of unconsolidated affiliate, net	68			73			199			164
Other, net	17			20			50			41
Total	(12		)	(8		)	1			(192		)

Income Before Income Taxes	267			276			777			524
Income tax expense	98			97			281			193
Net Income	$	169		$	179		$	496		$	331

Basic Earnings Per Share	$	0.39		$	0.42		$	1.15		$	0.77

Diluted Earnings Per Share	$	0.39		$	0.41		$	1.14		$	0.76

Dividends Declared Per Share	$	0.2675		$	0.2575		$	0.8025		$	0.7725

Weighted Average Shares Outstanding, Basic	431			431			431			431

Weighted Average Shares Outstanding, Diluted	434			433			434			433

See Notes to Interim Condensed Consolidated Financial Statements

Table of Contents

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

CONDENSED STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME

(In Millions)

(Unaudited)



	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2017			2016		2017			2016
Net income	$	169		$	179	$	496		$	331
Other comprehensive income:
Adjustment related to pension and other postretirement plans (net of tax of $2, $2, $4 and $1)	—			1		2			1
Net deferred gain (loss) from cash flow hedges (net of tax of $2, $1, $2 and $-0-)	(2		)	2		(3		)	1
Total	(2		)	3		(1		)	2
Comprehensive income	$	167		$	182	$	495		$	333

See Notes to Interim Condensed Consolidated Financial Statements

Table of Contents

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(In Millions)

(Unaudited)

ASSETS



	September 30, 2017		December 31, 2016
Current Assets:
Cash and cash equivalents ($200 and $340 related to VIEs, respectively)	$	201	$	341
Investment in marketable securities	1,057		953
Accounts receivable ($65 and $52 related to VIEs, respectively), less bad debt reserve of $16 and $15, respectively	783		740
Accrued unbilled revenues	213		335
Natural gas inventory	252		131
Materials and supplies	190		181
Non-trading derivative assets	64		51
Taxes receivable	—		30
Prepaid expenses and other current assets ($31 and $40 related to VIEs, respectively)	175		161
Total current assets	2,935		2,923

Property, Plant and Equipment:
Property, plant and equipment	18,581		17,831
Less: accumulated depreciation and amortization	5,881		5,524
Property, plant and equipment, net	12,700		12,307

Other Assets:
Goodwill	867		862
Regulatory assets ($1,690 and $1,919 related to VIEs, respectively)	2,539		2,677
Non-trading derivative assets	56		19
Investment in unconsolidated affiliate	2,481		2,505
Preferred units – unconsolidated affiliate	363		363
Other	194		173
Total other assets	6,500		6,599

Total Assets	$	22,135	$	21,829

See Notes to Interim Condensed Consolidated Financial Statements

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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS – (continued)

(In Millions, except share amounts)

(Unaudited)

LIABILITIES AND SHAREHOLDERS’ EQUITY



	September 30, 2017			December 31, 2016
Current Liabilities:
Short-term borrowings	$	48		$	35
Current portion of VIE securitization bonds long-term debt	432			411
Indexed debt, net	120			114
Current portion of other long-term debt	550			500
Indexed debt securities derivative	776			717
Accounts payable	657			657
Taxes accrued	199			172
Interest accrued	83			108
Non-trading derivative liabilities	17			41
Other	339			325
Total current liabilities	3,221			3,080

Other Liabilities:
Deferred income taxes, net	5,458			5,263
Non-trading derivative liabilities	10			5
Benefit obligations	886			913
Regulatory liabilities	1,127			1,298
Other	284			278
Total other liabilities	7,765			7,757

Long-term Debt:
VIE securitization bonds, net	1,500			1,867
Other long-term debt, net	6,031			5,665
Total long-term debt, net	7,531			7,532

Commitments and Contingencies (Note 13)

Shareholders’ Equity:
Cumulative preferred stock, $0.01 par value, 20,000,000 shares authorized, none issued or outstanding	—			—
Common stock, $0.01 par value, 1,000,000,000 shares authorized, 431,030,884 shares and 430,682,504 shares outstanding, respectively	4			4
Additional paid-in capital	4,204			4,195
Accumulated deficit	(518		)	(668		)
Accumulated other comprehensive loss	(72		)	(71		)
Total shareholders’ equity	3,618			3,460

Total Liabilities and Shareholders’ Equity	$	22,135		$	21,829

See Notes to Interim Condensed Consolidated Financial Statements

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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

(In Millions)

(Unaudited)



	Nine Months Ended September 30,
	2017			2016
Cash Flows from Operating Activities:
Net income	$	496		$	331
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	749			873
Amortization of deferred financing costs	18			19
Deferred income taxes	185			150
Unrealized gain on marketable securities	(104		)	(187		)
Loss on indexed debt securities	59			258
Write-down of natural gas inventory	—			1
Equity in earnings of unconsolidated affiliate, net of distributions	(199		)	(164		)
Pension contributions	(46		)	(7		)
Changes in other assets and liabilities, excluding acquisitions:
Accounts receivable and unbilled revenues, net	216			86
Inventory	(52		)	(5		)
Taxes receivable	30			149
Accounts payable	(137		)	(90		)
Fuel cost recovery	(30		)	(43		)
Non-trading derivatives, net	(53		)	23
Margin deposits, net	(49		)	65
Interest and taxes accrued	2			(48		)
Net regulatory assets and liabilities	(135		)	(26		)
Other current assets	21			(9		)
Other current liabilities	19			31
Other assets	(3		)	—
Other liabilities	28			29
Other, net	16			19
Net cash provided by operating activities	1,031			1,455
Cash Flows from Investing Activities:
Capital expenditures	(994		)	(1,047		)
Acquisitions, net of cash acquired	(132		)	(102		)
Decrease in notes receivable – unconsolidated affiliate	—			363
Investment in preferred units – unconsolidated affiliate	—			(363		)
Distributions from unconsolidated affiliate in excess of cumulative earnings	223			223
Decrease (increase) in restricted cash of Bond Companies	8			(2		)
Proceeds from sale of marketable securities	—			178
Other, net	3			11
Net cash used in investing activities	(892		)	(739		)
Cash Flows from Financing Activities:
Increase in short-term borrowings, net	13			3
Proceeds from (payments of) commercial paper, net	(428		)	63
Proceeds from long-term debt, net	1,096			600
Payments of long-term debt	(597		)	(855		)
Debt issuance costs	(13		)	(9		)
Payment of dividends on common stock	(346		)	(332		)
Distribution to ZENS note holders	—			(178		)
Other, net	(4		)	(2		)
Net cash used in financing activities	(279		)	(710		)
Net Increase (Decrease) in Cash and Cash Equivalents	(140		)	6
Cash and Cash Equivalents at Beginning of Period	341			264
Cash and Cash Equivalents at End of Period	$	201		$	270
Supplemental Disclosure of Cash Flow Information:
Cash Payments/Receipts:
Interest, net of capitalized interest	$	306		$	324
Income taxes (refunds), net	14			(105		)
Non-cash transactions:
Accounts payable related to capital expenditures	111			75

See Notes to Interim Condensed Consolidated Financial Statements

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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(1) Background and Basis of Presentation

General. Included in this Form 10-Q are the Interim Condensed Financial Statements of CenterPoint Energy. The Interim Condensed Financial Statements are unaudited, omit certain financial statement disclosures and should be read with the 2016 Form 10-K.

Background. CenterPoint Energy, Inc. is a public utility holding company. CenterPoint Energy’s 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. CenterPoint Energy’s 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 33 states.

As of September 30, 2017, CenterPoint Energy 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 common units representing limited partner interests in Enable.

As of September 30, 2017, CenterPoint Energy had VIEs consisting of the Bond Companies, which it consolidates. The consolidated VIEs are wholly-owned, bankruptcy-remote, special purpose entities that were formed specifically for the purpose of securitizing transition and system restoration-related property. Creditors of CenterPoint Energy have no recourse to any assets or revenues of the Bond Companies. The bonds issued by these VIEs are payable only from and secured by transition and system restoration property, and the bondholders have no recourse to the general credit of CenterPoint Energy.

Basis of Presentation. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

CenterPoint Energy’s Interim Condensed Financial Statements reflect all normal recurring adjustments that are, in the opinion of management, necessary to present fairly the financial position, results of operations and cash flows for the respective periods. Amounts reported in CenterPoint Energy’s Condensed Statements of Consolidated Income are not necessarily indicative of amounts expected for a full-year period due to the effects of, among other things, (a) seasonal fluctuations in demand for energy and energy services, (b) changes in energy commodity prices, (c) timing of maintenance and other expenditures and (d) acquisitions and dispositions of businesses, assets and other interests.

For a description of CenterPoint Energy’s reportable business segments, see Note 15.

(2) New Accounting Pronouncements

In January 2016, the FASB issued ASU No. 2016-01, Financial Instruments-Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities (ASU 2016-01). ASU 2016-01 requires equity investments that do not result in consolidation and are not accounted for under the equity method to be measured at fair value and to recognize any changes in fair value in net income unless the investments qualify for the new practicability exception. It does not change the guidance for classifying and measuring investments in debt securities and loans. ASU 2016-01 also changes certain disclosure requirements and other aspects related to recognition and measurement of financial assets and financial liabilities. ASU 2016-01 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2017. As of the first reporting period in which the guidance is adopted, a cumulative-effect adjustment to beginning retained earnings will be made, with two features that will be adopted prospectively. CenterPoint Energy does not believe this standard will have a material impact on its financial position, results of operations, cash flows and disclosures.

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In 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02) and related amendments. ASU 2016-02 provides a comprehensive new lease model that requires lessees to recognize assets and liabilities for most leases and would change certain aspects of lessor accounting. ASU 2016-02 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted. A modified retrospective adoption approach is required. CenterPoint Energy is currently assessing the impact that this standard will have on its financial position, results of operations, cash flows and disclosures.

In March 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). The new guidance simplifies several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. CenterPoint Energy adopted this standard as of January 1, 2017. The adoption did not have a material impact on CenterPoint Energy’s financial position or results of operations. However, CenterPoint Energy’s statement of cash flows reflects a decrease in financing activity and a corresponding increase in operating activity of $4 million and $3 million as of September 30, 2017 and 2016, respectively, due to the retrospective application of the requirement that cash paid to a tax authority when shares are withheld to satisfy statutory income tax withholding obligations should be presented as a financing rather than as an operating activity.

In 2016, the FASB issued ASUs which amended ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606). ASU 2014-09, as amended, provides a comprehensive new revenue recognition model that requires revenue to be recognized in a manner that depicts the transfer of goods or services to a customer at an amount that reflects the consideration expected to be received in exchange for those goods or services. Early adoption is permitted, and entities have the option of using either a full retrospective or a modified retrospective adoption approach. CenterPoint Energy is currently evaluating its revenue streams under these ASUs and has not yet identified any significant changes as the result of these new standards. A substantial amount of CenterPoint Energy’s revenues are tariff and derivative based, which we do not anticipate will be significantly impacted by these ASUs. CenterPoint Energy expects to adopt these ASUs on January 1, 2018 using the modified retrospective adoption approach.

In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (ASU 2016-15). ASU 2016-15 provides clarifying guidance on the classification of certain cash receipts and payments in the statement of cash flows and eliminates the variation in practice related to such classifications. ASU 2016-15 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017, with early adoption permitted. A retrospective adoption approach is required. CenterPoint Energy is currently assessing the impact that this standard will have on its statement of cash flows.

In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (ASU 2016-18). ASU 2016-18 requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, restricted cash and restricted cash equivalents. As a result, the statement of cash flows will no longer present transfers between cash and cash equivalents and restricted cash and restricted cash equivalents. When cash, cash equivalents, restricted cash and restricted cash equivalents are presented in more than one line item on the balance sheet, the new guidance requires a reconciliation of the totals in the statement of cash flows to the related captions in the balance sheet. ASU 2016-18 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017, with early adoption permitted. A retrospective adoption approach is required. This standard will not have an impact on CenterPoint Energy’s financial position, results of operations, and disclosures, but it will have an impact on the presentation of the statement of cash flows.

In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business (ASU 2017-01). ASU 2017-01 revises the definition of a business. If substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or a group of similar identifiable assets, then under ASU 2017-01, the asset or group of assets is not a business. The guidance also requires a business to include at least one substantive process and narrows the definition of outputs to be more closely aligned with how outputs are described in ASC 606. ASU 2017-01 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017, with early adoption permitted in certain circumstances. A prospective adoption approach is required. ASU 2017-01 could have a potential impact on CenterPoint Energy’s accounting for future acquisitions.

In January 2017, the FASB issued ASU No. 2017-04, Intangibles-Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment (ASU 2017-04). ASU 2017-04 eliminates Step 2 of the goodwill impairment test, which requires a hypothetical purchase price allocation. A goodwill impairment will now be the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill. ASU 2017-04 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019, with early adoption permitted. A prospective adoption approach is required. ASU 2017-04 will have an impact on CenterPoint Energy’s future calculation of goodwill impairments if an impairment is identified.

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In February 2017, the FASB issued ASU No. 2017-05, Other Income-Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20): Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets (ASU 2017-05). ASU 2017-05 clarifies when and how to apply ASC 610-20 Gains and Losses from the Derecognition of Nonfinancial Assets, which was issued as part of ASU 2014-09 Revenue from Contracts with Customers (Topic 606). ASU 2017-05 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017, with early adoption permitted. Companies can elect a retrospective or modified retrospective approach to adoption. CenterPoint Energy does not believe this standard will have a material impact on its financial position, results of operations, cash flows and disclosures.

In March 2017, the FASB issued ASU No. 2017-07, Compensation-Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires an employer to report the service cost component of the net periodic pension cost and postretirement benefit cost in the same line item(s) as other employee compensation costs arising from services rendered during the period; all other components will be presented separately from the line item(s) that includes the service cost and outside of any subtotal of operating income. In addition, only the service cost component will be eligible for capitalization in assets. ASU 2017-07 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017, with early adoption permitted. ASU 2017-07 should be applied retrospectively for the presentation of the service cost component and the other components and prospectively for the capitalization of the service cost component. The adoption of this guidance is expected to result in an increase to operating income and a decrease to other income. Prospectively, other components previously capitalized in assets will be recorded as regulatory assets in CenterPoint Energy’s rate-regulated businesses. CenterPoint Energy does not believe this standard will have a material impact on its financial position, results of operations, cash flows and disclosures.

In May 2017, the FASB issued ASU No. 2017-09, Compensation-Stock Compensation (Topic 718): Scope of Modification Accounting (ASU 2017-09). ASU 2017-09 clarifies when changes to the terms or conditions of a share-based payment award must be accounted for as a modification. Entities will apply the modification accounting guidance if the value, vesting conditions or classification of the award changes. ASU 2017-09 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017, with early adoption permitted. ASU 2017-09 should be applied prospectively for awards modified on or after the adoption date. This standard will have an impact on CenterPoint Energy’s future treatment of changes to share-based payment awards.

In August 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12). ASU 2017-12 expands an entity’s ability to hedge nonfinancial and financial risk components and reduce complexity in fair value hedges of interest rate risk. The guidance eliminates the requirement to separately measure and report hedge ineffectiveness, eases certain documentation and assessment requirements, and updates the presentation and disclosure requirements. ASU 2017-12 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted. A cumulative-effect adjustment to eliminate the separate measurement of ineffectiveness upon adoption is required for existing cash flow and net investment hedges. Presentation and disclosure guidance should be applied prospectively. CenterPoint Energy is currently assessing the impact that this standard will have on its financial position, results of operations, cash flows and disclosures.

Management believes that other recently issued standards, which are not yet effective, will not have a material impact on CenterPoint Energy’s consolidated financial position, results of operations or cash flows upon adoption.

(3) Acquisition

On January 3, 2017, CES, an indirect, wholly-owned subsidiary of CenterPoint Energy, completed its acquisition of AEM. After working capital adjustments, the final purchase price was $147 million and was allocated to identifiable assets acquired and liabilities assumed based on their estimated fair values on the acquisition date.

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The following table summarizes the final purchase price allocation and the fair value amounts recognized for the assets acquired and liabilities assumed related to the acquisition:



	(in millions)
Total purchase price consideration	$	147
Cash	$	15
Receivables	140
Natural gas inventory	78
Derivative assets	35
Prepaid expenses and other current assets	5
Property and equipment	8
Identifiable intangibles	25
Total assets acquired	306
Accounts payable	113
Derivative liabilities	43
Other current liabilities	7
Other liabilities	1
Total liabilities assumed	164
Identifiable net assets acquired	142
Goodwill	5
Net assets acquired	$	147

The goodwill of $5 million resulting from the acquisition reflects the excess of the purchase price over the fair value of the net identifiable assets acquired. The goodwill recorded as part of the acquisition primarily reflects the value of the complementary operational and geographic footprints, scale and expanded capabilities provided by the acquisition.

Identifiable intangible assets were recorded at estimated fair value as determined by management based on available information, which includes a preliminary valuation prepared by an independent third party. The significant assumptions used in arriving at the estimated identifiable intangible asset values included management’s estimates of future cash flows, the discount rate which is based on the weighted average cost of capital for comparable publicly traded guideline companies and projected customer attrition rates. The useful lives for the identifiable intangible assets were determined using methods that approximate the pattern of economic benefit provided by the utilization of the assets.

The estimated fair value of the identifiable intangible assets and related useful lives as included in the final purchase price allocation include:

Amortization expense related to the above identifiable intangible assets was $-0- and $1 million for the three and nine months ended September 30, 2017, respectively.

Revenues of approximately $311 million and $989 million, respectively, and operating income of approximately $3 million and $28 million, respectively, attributable to the AEM acquisition are reported in the Energy Services business segment and included in CenterPoint Energy’s Condensed Statements of Consolidated Income for the three and nine months ended September 30, 2017.

The following unaudited pro forma financial information reflects the consolidated results of operations of CenterPoint Energy, assuming the AEM acquisition had taken place on January 1, 2016. Adjustments to pro forma net income include intercompany sales, amortization of intangible assets, depreciation of fixed assets, interest expense associated with debt financing to fund the acquisition, and related income tax effects. The pro forma information does not include the mark-to-market impact of financial instruments designated as cash flow hedges of anticipated purchases and sales at index prices. The effective portion of these hedges are excluded from earnings and reported as changes in Other Comprehensive Income. Additionally, the pro forma information does not include the mark-to-market impact of physical forward transactions that were previously accounted for as normal purchase and sale transactions.

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The unaudited pro forma financial information has been presented for illustrative purposes only and is not necessarily indicative of the consolidated results of operations that would have been achieved had the acquisition taken place on the dates indicated or the future consolidated results of operations of the combined company.



	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(in millions)
Operating Revenue	$	2,098	$	2,145	$	6,976	$	6,161
Net Income	169		179		496		335

(4) Employee Benefit Plans

CenterPoint Energy’s net periodic cost includes the following components relating to pension and postretirement benefits:



	Three Months Ended September 30,
	2017						2016
	Pension Benefits			Postretirement Benefits			Pension Benefits			Postretirement Benefits
	(in millions)
Service cost	$	9		$	—		$	10		$	1
Interest cost	22			4			23			4
Expected return on plan assets	(24		)	(1		)	(26		)	(2		)
Amortization of prior service cost (credit)	2			(1		)	3			(1		)
Amortization of net loss	14			—			15			—
Net periodic cost (2)	$	23		$	2		$	25		$	2

	Nine Months Ended September 30,
	2017						2016
	Pension Benefits			Postretirement Benefits			Pension Benefits			Postretirement Benefits
	(in millions)
Service cost	$	27		$	1		$	28		$	2
Interest cost	66			12			70			13
Expected return on plan assets	(72		)	(4		)	(76		)	(5		)
Amortization of prior service cost (credit)	7			(3		)	7			(2		)
Amortization of net loss	43			—			47			—
Curtailment gain (1)	—			—			—			(3		)
Net periodic cost (2)	$	71		$	6		$	76		$	5

(1)

A curtailment gain or loss is required when the expected future services of a significant number of current employees are reduced or eliminated for the accrual of benefits. In May 2016, Houston Electric entered into a renegotiated collective bargaining agreement with the IBEW Local Union 66 that provides that for Houston Electric union employees covered under the agreement who retire on or after January 1, 2017, retiree medical and prescription drug coverage will be provided exclusively through the NECA/IBEW Family Medical Care Plan in exchange for the payment of monthly premiums as determined under the agreement. As a result, the accrued postretirement benefits related to such future Houston Electric union retirees were eliminated. In 2016, Houston Electric recognized a curtailment gain of $3 million as an accelerated recognition of the prior service credit that would otherwise be recognized in future periods.


(2)	Net periodic cost in this table is before considering amounts subject to overhead allocations for capital expenditure projects or for amounts subject to deferral for regulatory purposes.

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CenterPoint Energy’s changes in accumulated comprehensive loss related to defined benefit and postretirement plans are as follows:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(in millions)
Beginning Balance	$	(70	)	$	(65	)	$	(72	)	$	(65	)
Other comprehensive income (loss) before reclassifications (1)	—			—			—			(4		)
Amounts reclassified from accumulated other comprehensive loss:
Prior service cost (2)	—			1			1			1
Actuarial losses (2)	2			2			5			5
Tax expense	(2		)	(2		)	(4		)	(1		)
Net current period other comprehensive income	—			1			2			1
Ending Balance	$	(70	)	$	(64	)	$	(70	)	$	(64	)


(1)	Total other comprehensive income (loss) is related to the remeasurement of the postretirement plan.


(2)	These accumulated other comprehensive components are included in the computation of net periodic cost.

CenterPoint Energy expects to contribute a minimum of approximately $46 million to its pension plans in 2017, of which approximately $28 million and $46 million were contributed during the three and nine months ended September 30, 2017, respectively.

CenterPoint Energy expects to contribute a total of approximately $16 million to its postretirement benefit plan in 2017, of which approximately $4 million and $12 million were contributed during the three and nine months ended September 30, 2017, respectively.

(5) Regulatory Accounting

Equity Return. As of September 30, 2017, Houston Electric has not recognized an allowed equity return of $299 million because such return will be recognized as it is recovered in rates. During the three months ended September 30, 2017 and 2016, Houston Electric recognized approximately $13 million and $22 million, respectively, of the allowed equity return not previously recognized. During the nine months ended September 30, 2017 and 2016, Houston Electric recognized approximately $30 million and $52 million, respectively, of the allowed equity return not previously recognized.

Hurricane Harvey. Houston Electric’s electric delivery system and CERC Corp.’s NGD suffered damage as a result of Hurricane Harvey, a major storm classified as a Category 4 hurricane on the Saffir-Simpson Hurricane Wind Scale, that first struck the Texas coast on Friday, August 25, 2017 and remained over the Houston area for the next several days. The unprecedented flooding from torrential amounts of rainfall accompanying the storm caused significant damage to or destruction of residences and businesses served by Houston Electric and NGD.

Currently, Houston Electric estimates that total costs to restore the electric delivery facilities damaged as a result of Hurricane Harvey will range from $110 million to $120 million and estimates that the total restoration costs covered by insurance will be approximately $35 million. Houston Electric will defer the uninsured storm restoration costs as management believes it is probable that such costs will be recovered through traditional rate adjustment mechanisms for capital costs and through the next rate proceeding for operation and maintenance expenses. As of September 30, 2017, Houston Electric recorded an increase of $4 million in property, plant and equipment and $73 million in regulatory assets, net of $23 million in insurance receivables recorded, for restoration costs incurred. As a result, storm restoration costs should not materially affect Houston Electric’s reported net income for 2017.

Currently, NGD estimates that total costs to restore natural gas distribution facilities damaged as a result of Hurricane Harvey will range from $25 million to $30 million and estimates that the total restoration costs covered by insurance will be approximately $17 million. NGD will defer the uninsured storm restoration costs as management believes it is probable that such costs will be recovered through traditional rate adjustment mechanisms for capital costs and through the next rate proceeding for operation and maintenance expenses. As of September 30, 2017, NGD has recorded approximately $7 million in regulatory assets, net of $2

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million of insurance receivables recorded, for restoration costs incurred. As a result, storm restoration costs should not materially affect CERC’s reported net income for 2017.

(6) Derivative Instruments

CenterPoint Energy is exposed to various market risks. These risks arise from transactions entered into in the normal course of business. CenterPoint Energy utilizes derivative instruments such as physical forward contracts, swaps and options to mitigate the impact of changes in commodity prices, weather and interest rates on its operating results and cash flows. Such derivatives are recognized in CenterPoint Energy’s Condensed Consolidated Balance Sheets at their fair value unless CenterPoint Energy elects the normal purchase and sales exemption for qualified physical transactions. A derivative may be designated as a normal purchase or sale if the intent is to physically receive or deliver the product for use or sale in the normal course of business.

CenterPoint Energy has a Risk Oversight Committee composed of corporate and business segment officers that oversees commodity price, weather and credit risk activities, including CenterPoint Energy’s marketing, risk management services and hedging activities. The committee’s duties are to establish CenterPoint Energy’s commodity risk policies, allocate board-approved commercial risk limits, approve the use of new products and commodities, monitor positions and ensure compliance with CenterPoint Energy’s risk management policies, procedures and limits established by CenterPoint Energy’s board of directors.

CenterPoint Energy’s policies prohibit the use of leveraged financial instruments. A leveraged financial instrument, for this purpose, is a transaction involving a derivative whose financial impact will be based on an amount other than the notional amount or volume of the instrument.


(a)	Non-Trading Activities

Derivative Instruments. CenterPoint Energy enters into certain derivative instruments to mitigate the effects of commodity price movements. Certain financial instruments used to hedge portions of the natural gas inventory of the Energy Services business segment are designated as fair value hedges for accounting purposes. All other financial instruments do not qualify or are not designated as cash flow or fair value hedges.

Weather Hedges. CenterPoint Energy has weather normalization or other rate mechanisms that mitigate the impact of weather on NGD in Arkansas, Louisiana, Mississippi, Minnesota and Oklahoma. NGD and electric operations in Texas do not have such mechanisms, although fixed customer charges are historically higher in Texas for NGD compared to CenterPoint Energy’s other jurisdictions. As a result, fluctuations from normal weather may have a positive or negative effect on NGD’s results in Texas and on Houston Electric’s results in its service territory.

CenterPoint Energy entered into heating-degree day swaps for certain NGD Texas jurisdictions to mitigate the effect of fluctuations from normal weather on its results of operations and cash flows for the 2017–2018 winter heating season, which contained a bilateral dollar cap of $8 million. However, CenterPoint Energy did not enter into heating-degree day swaps for NGD jurisdictions for the 2015–2016 or 2016–2017 winter heating seasons. CenterPoint Energy entered into weather hedges for the Houston Electric service territory to mitigate the effect of fluctuations from normal weather on its results of operations and cash flows, which contained bilateral dollar caps of $7 million, $9 million and $9 million for the 2015–2016, 2016–2017 and 2017–2018 winter seasons, respectively. The swaps are based on heating degree days at 10-year normal weather. During both the three months ended September 30, 2017 and 2016, CenterPoint Energy recognized no gains or losses related to these swaps. During the nine months ended September 30, 2017 and 2016, CenterPoint Energy recognized gains of $1 million and $3 million, respectively, related to these swaps. Weather hedge gains and losses are included in revenues in the Condensed Statements of Consolidated Income.

Hedging of Interest Expense for Future Debt Issuances. In January 2017, Houston Electric entered into forward interest rate agreements with several counterparties, having an aggregate notional amount of $150 million. These agreements were executed to hedge, in part, volatility in the 10-year U.S. treasury rate by reducing Houston Electric’s exposure to variability in cash flows related to interest payments of Houston Electric’s $300 million issuance of fixed rate debt in January 2017. These forward interest rate agreements were designated as cash flow hedges. Accordingly, the effective portion of realized losses associated with the agreements, which totaled approximately $0.5 million, is a component of accumulated other comprehensive income in 2017 and will be amortized over the life of the bonds.

In 2017, CenterPoint Energy entered into forward interest rate agreements with several counterparties, having an aggregate notional amount of $350 million. These agreements were executed to hedge, in part, volatility in the 5-year U.S. treasury rate by reducing CenterPoint Energy’s exposure to variability in cash flows relating to interest payments of CenterPoint Energy’s $500 million issuance of fixed rate debt in August 2017. These forward interest rate agreements were designated as cash flow hedges.

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Accordingly, the effective portion of realized losses associated with the agreements, which totaled approximately $2.9 million, is a component of accumulated other comprehensive income in 2017 and will be amortized over the life of the notes.

In August 2017, CERC Corp. entered into forward interest rate agreements with several counterparties, having an aggregate notional amount of $150 million. These agreements were executed to hedge, in part, volatility in the 30-year U.S. treasury rate by reducing CERC Corp.’s exposure to variability in cash flows related to interest payments of CERC Corp.’s $300 million issuance of fixed rate debt in August 2017. These forward interest rate agreements were designated as cash flow hedges. Accordingly, the effective portion of realized losses associated with the agreements, which totaled approximately $1.5 million, is a component of accumulated other comprehensive income in 2017 and will be amortized over the life of the notes.


(b)	Derivative Fair Values and Income Statement Impacts

The following tables present information about CenterPoint Energy’s derivative instruments and hedging activities. The first four tables provide a balance sheet overview of CenterPoint Energy’s Derivative Assets and Liabilities as of September 30, 2017 and December 31, 2016, while the last table provides a breakdown of the related income statement impacts for the three and nine months ended September 30, 2017 and 2016.



Fair Value of Derivative Instruments
	September 30, 2017
Derivatives designated as fair value hedges:	Balance Sheet Location	Derivative Assets Fair Value		Derivative Liabilities Fair Value
		(in millions)
Natural gas derivatives (1) (2) (3)	Current Assets: Non-trading derivative assets	$	—	$	—
Natural gas derivatives (1) (2) (3)	Current Liabilities: Non-trading derivative liabilities	5		—

Derivatives not designated as hedging instruments:
Natural gas derivatives (1) (2) (3)	Current Assets: Non-trading derivative assets	65		2
Natural gas derivatives (1) (2) (3)	Other Assets: Non-trading derivative assets	58		2
Natural gas derivatives (1) (2) (3)	Current Liabilities: Non-trading derivative liabilities	27		55
Natural gas derivatives (1) (2) (3)	Other Liabilities: Non-trading derivative liabilities	9		25
Indexed debt securities derivative	Current Liabilities	—		776
Total		$	164	$	860


(1)	The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling 1,866 Bcf or a net 46 Bcf long position. Certain natural gas contracts hedge basis risk only and lack a fixed price exposure.

(2)

Natural gas contracts are presented on a net basis in the Condensed Consolidated Balance Sheets as they are subject to master netting arrangements. This netting applies to all undisputed amounts due or past due and causes derivative assets (liabilities) to be ultimately presented net in a liability (asset) account within the Condensed Consolidated Balance Sheets. The net of total non-trading natural gas derivative assets and liabilities was a $93 million asset as shown on CenterPoint Energy’s Condensed Consolidated Balance Sheets (and as detailed in the table below), and was comprised of the natural gas contracts derivative assets and liabilities separately shown above, impacted by collateral netting of $13 million.


(3)	Derivative Assets and Derivative Liabilities include no material amounts related to physical forward transactions with Enable.

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Offsetting of Natural Gas Derivative Assets and Liabilities
	September 30, 2017
	Gross Amounts Recognized (1)			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amount Presented in the Consolidated Balance Sheets (2)
	(in millions)
Current Assets: Non-trading derivative assets	$	97		$	(33	)	$	64
Other Assets: Non-trading derivative assets	67			(11		)	56
Current Liabilities: Non-trading derivative liabilities	(57		)	40			(17		)
Other Liabilities: Non-trading derivative liabilities	(27		)	17			(10		)
Total	$	80		$	13		$	93


(1)	Gross amounts recognized include some derivative assets and liabilities that are not subject to master netting arrangements.


(2)	The derivative assets and liabilities on the Condensed Consolidated Balance Sheets exclude accounts receivable or accounts payable that, should they exist, could be used as offsets to these balances in the event of a default.



Fair Value of Derivative Instruments
	December 31, 2016
Derivatives not designated as hedging instruments	Balance Sheet Location	Derivative Assets Fair Value		Derivative Liabilities Fair Value
		(in millions)
Natural gas derivatives (1) (2) (3)	Current Assets: Non-trading derivative assets	$	79	$	14
Natural gas derivatives (1) (2) (3)	Other Assets: Non-trading derivative assets	24		5
Natural gas derivatives (1) (2) (3)	Current Liabilities: Non-trading derivative liabilities	2		43
Natural gas derivatives (1) (2) (3)	Other Liabilities: Non-trading derivative liabilities	—		5
Indexed debt securities derivative	Current Liabilities	—		717
Total (4)		$	105	$	784


(1)	The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling 1,035 Bcf or a net 59 Bcf long position. Certain natural gas contracts hedge basis risk only and lack a fixed price exposure.

(2)

Natural gas contracts are presented on a net basis in the Condensed Consolidated Balance Sheets as they are subject to master netting arrangements. This netting applies to all undisputed amounts due or past due and causes derivative assets (liabilities) to be ultimately presented net in a liability (asset) account within the Condensed Consolidated Balance Sheets. The net of total non-trading natural gas derivative assets and liabilities was a $24 million asset as shown on CenterPoint Energy’s Condensed Consolidated Balance Sheets (and as detailed in the table below), and was comprised of the natural gas contracts derivative assets and liabilities separately shown above, impacted by collateral netting of $14 million.


(3)	Derivative Assets and Derivative Liabilities include no material amounts related to physical forward transactions with Enable.


(4)	No derivatives were designated as fair value hedges as of December 31, 2016.



Offsetting of Natural Gas Derivative Assets and Liabilities
	December 31, 2016
	Gross Amounts Recognized (1)			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amount Presented in the Consolidated Balance Sheets (2)
	(in millions)
Current Assets: Non-trading derivative assets	$	81		$	(30	)	$	51
Other Assets: Non-trading derivative assets	24			(5		)	19
Current Liabilities: Non-trading derivative liabilities	(57		)	16			(41		)
Other Liabilities: Non-trading derivative liabilities	(10		)	5			(5		)
Total	$	38		$	(14	)	$	24

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(1)	Gross amounts recognized include some derivative assets and liabilities that are not subject to master netting arrangements.


(2)	The derivative assets and liabilities on the Condensed Consolidated Balance Sheets exclude accounts receivable or accounts payable that, should they exist, could be used as offsets to these balances in the event of a default.

Realized and unrealized gains and losses on natural gas derivatives are recognized in the Condensed Statements of Consolidated Income as revenue for physical sales derivative contracts and as natural gas expense for financial natural gas derivatives and physical purchase natural gas derivatives. Realized and unrealized gains and losses on indexed debt securities are recorded as Other Income (Expense) in the Condensed Statements of Consolidated Income.

Hedge ineffectiveness is recorded as a component of natural gas expense and primarily results from differences in the location of the derivative instrument and the hedged item. Basis ineffectiveness arises from natural gas market price differences between the locations of the hedged inventory and the delivery location specified in the hedge instruments. The impact of natural gas derivatives designated as fair value hedges, the related hedged item, and natural gas derivatives not designated as hedging instruments are presented in the table below.



Income Statement Impact of Derivative Activity
		Three Months Ended September 30,
	Income Statement Location	2017			2016
Derivatives designated as fair value hedges:		(in millions)
Natural gas derivatives	Gains (Losses) in Expenses: Natural Gas	$	(4	)	$	—
Fair value adjustments for natural gas inventory designated as the hedged item	Gains (Losses) in Expenses: Natural Gas	4			—
Total increase in Expenses: Natural Gas (1)		$	—		$	—

Derivatives not designated as hedging instruments:
Natural gas derivatives	Gains (Losses) in Revenues	$	30		$	31
Natural gas derivatives	Gains (Losses) in Expenses: Natural Gas	(9		)	(13		)
Indexed debt securities derivative	Gains (Losses) in Other Income (Expense)	(36		)	(72		)
Total - derivatives not designated as hedging instruments		$	(15	)	$	(54	)



Income Statement Impact of Derivative Activity
		Nine Months Ended September 30,
	Income Statement Location	2017			2016
Derivatives designated as fair value hedges:		(in millions)
Natural gas derivatives	Gains (Losses) in Expenses: Natural Gas	$	8		$	—
Fair value adjustments for natural gas inventory designated as the hedged item	Gains (Losses) in Expenses: Natural Gas	(10		)	—
Total increase in Expenses: Natural Gas (1)		$	(2	)	$	—

Derivatives not designated as hedging instruments:
Natural gas derivatives	Gains (Losses) in Revenues	$	162		$	1
Natural gas derivatives	Gains (Losses) in Expenses: Natural Gas	(91		)	35
Indexed debt securities derivative	Gains (Losses) in Other Income (Expense)	(59		)	(258		)
Total - derivatives not designated as hedging instruments		$	12		$	(222	)

(1)

Hedge ineffectiveness results from the basis ineffectiveness discussed above, and excludes the impact to natural gas expense from timing ineffectiveness. Timing ineffectiveness arises due to changes in the difference between the spot price and the futures price, as well as the difference between the timing of the settlement of the futures and the valuation of the underlying physical commodity. As the commodity contract nears the settlement date, spot-to-forward price differences should converge, which should reduce or eliminate the impact of this ineffectiveness on natural gas expense.

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(c)	Credit Risk Contingent Features

CenterPoint Energy enters into financial derivative contracts containing material adverse change provisions. These provisions could require CenterPoint Energy to post additional collateral if the S&P or Moody’s credit ratings of CenterPoint Energy, Inc. or its subsidiaries are downgraded. The total fair value of the derivative instruments that contain credit risk contingent features that are in a net liability position as of both September 30, 2017 and December 31, 2016 was $1 million. CenterPoint Energy posted no assets as collateral toward derivative instruments that contain credit risk contingent features as of either September 30, 2017 or December 31, 2016. If all derivative contracts (in a net liability position) containing credit risk contingent features were triggered as of September 30, 2017 and December 31, 2016, $1 million and $-0-, respectively, of additional assets would be required to be posted as collateral.

(7) Fair Value Measurements

Assets and liabilities that are recorded at fair value in the Condensed Consolidated Balance Sheets are categorized based upon the level of judgment associated with the inputs used to measure their value. Hierarchical levels, as defined below and directly related to the amount of subjectivity associated with the inputs to fair valuations of these assets and liabilities, are as follows:

Level 1: Inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date. The types of assets carried at Level 1 fair value generally are exchange-traded derivatives and equity securities, as well as natural gas inventory that has been designated as the hedged item in a fair value hedge.

Level 2: Inputs, other than quoted prices included in Level 1, are observable for the asset or liability, either directly or indirectly. Level 2 inputs include quoted prices for similar instruments in active markets, and inputs other than quoted prices that are observable for the asset or liability. Fair value assets and liabilities that are generally included in this category are derivatives with fair values based on inputs from actively quoted markets. A market approach is utilized to value CenterPoint Energy’s Level 2 assets or liabilities.

Level 3: Inputs are unobservable for the asset or liability, and include situations where there is little, if any, market activity for the asset or liability. Unobservable inputs reflect CenterPoint Energy’s judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. CenterPoint Energy develops these inputs based on the best information available, including CenterPoint Energy’s own data. A market approach is utilized to value CenterPoint Energy’s Level 3 assets or liabilities. As of September 30, 2017, CenterPoint Energy’s Level 3 assets and liabilities are comprised of physical natural gas forward contracts and options and its indexed debt securities. Level 3 physical natural gas forward contracts are valued using a discounted cash flow model which includes illiquid forward price curve locations (ranging from $1.08 to $5.83 per MMBtu) as an unobservable input. Level 3 options are valued through Black-Scholes (including forward start) option models which include option volatilities (ranging from 0% to 87%) as an unobservable input. CenterPoint Energy’s Level 3 physical natural gas forward contracts and options derivative assets and liabilities consist of both long and short positions (forwards and options) and their fair value is sensitive to forward prices and volatilities. If forward prices decrease, CenterPoint Energy’s long forwards lose value whereas its short forwards gain in value. If volatility decreases, CenterPoint Energy’s long options lose value whereas its short options gain in value. CenterPoint Energy’s Level 3 indexed debt securities are valued using a Black-Scholes option model and a discounted cash flow model, which use option volatility (11.4%) and a projected dividend growth rate (7%) as unobservable inputs. An increase in either volatilities or projected dividends will increase the value of the indexed debt securities, and a decrease in either the volatilities or projected dividends will decrease the value of the indexed debt securities.

CenterPoint Energy determines the appropriate level for each financial asset and liability on a quarterly basis and recognizes transfers between levels at the end of the reporting period. For the nine months ended September 30, 2017, there were no transfers between Level 1 and 2. CenterPoint Energy also recognizes purchases of Level 3 financial assets and liabilities at their fair market value at the end of the reporting period.

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The following tables present information about CenterPoint Energy’s assets and liabilities (including derivatives that are presented net) measured at fair value on a recurring basis as of September 30, 2017 and December 31, 2016, and indicate the fair value hierarchy of the valuation techniques utilized by CenterPoint Energy to determine such fair value.



	September 30, 2017
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Netting Adjustments (1)			Balance
			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Netting Adjustments (1)			Balance
	(in millions)
Assets
Corporate equities	$	1,060	$	—	$	—	$	—		$	1,060
Investments, including money market funds (2)	67		—		—		—			67
Natural gas derivatives (3)	3		128		33		(44		)	120
Hedged portion of natural gas inventory	65		—		—		—			65
Total assets	$	1,195	$	128	$	33	$	(44	)	$	1,312
Liabilities
Indexed debt securities derivative	$	—	$	—	$	776	$	—		$	776
Natural gas derivatives (3)	3		74		7		(57		)	27
Total liabilities	$	3	$	74	$	783	$	(57	)	$	803


(1)	Amounts represent the impact of legally enforceable master netting arrangements that allow CenterPoint Energy to settle positive and negative positions and also include cash collateral of $13 million posted with the same counterparties.


(2)	Amounts are included in Prepaid Expenses and Other Current Assets in the Condensed Consolidated Balance Sheets.


(3)	Natural gas derivatives include no material amounts related to physical forward transactions with Enable.



	December 31, 2016
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Netting Adjustments (1)			Balance
			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Netting Adjustments (1)			Balance
	(in millions)
Assets
Corporate equities	$	956	$	—	$	—	$	—		$	956
Investments, including money market funds (2)	77		—		—		—			77
Natural gas derivatives (3)	11		74		20		(35		)	70
Total assets	$	1,044	$	74	$	20	$	(35	)	$	1,103
Liabilities
Indexed debt securities derivative	$	—	$	—	$	717	$	—		$	717
Natural gas derivatives (3)	4		56		7		(21		)	46
Total liabilities	$	4	$	56	$	724	$	(21	)	$	763


(1)	Amounts represent the impact of legally enforceable master netting arrangements that allow CenterPoint Energy to settle positive and negative positions and also include cash collateral of $14 million held by CES from the same counterparties.


(2)	Amounts are included in Prepaid Expenses and Other Current Assets in the Condensed Consolidated Balance Sheets.


(3)	Natural gas derivatives include no material amounts related to physical forward transactions with Enable.

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The following table presents additional information about assets or liabilities, including derivatives that are measured at fair value on a recurring basis for which CenterPoint Energy has utilized Level 3 inputs to determine fair value:



	Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Derivative assets and liabilities, net
	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(in millions)
Beginning balance	$	(712	)	$	16		$	(704	)	$	12
Purchases (1)	—			—			—			12
Total gains (losses)	(38		)	9			(38		)	13
Total settlements	(1		)	(8		)	(5		)	(24		)
Transfers into Level 3	7			—			9			5
Transfers out of Level 3	(6		)	—			(12		)	(1		)
Ending balance (2)	$	(750	)	$	17		$	(750	)	$	17
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the reporting date (3)	$	(36	)	$	6		$	(42	)	$	14


(1)	Mark-to-market value of Level 3 derivative assets acquired through the purchase of AEM was less than $1 million at the acquisition date.


(2)	CenterPoint Energy did not have significant Level 3 sales during either of the three or nine months ended September 30, 2017 or 2016.

(3)

During 2016, CenterPoint Energy transferred its indexed debt securities from Level 2 to Level 3 to reflect changes in the significance of the unobservable inputs used in the valuation. As of September 30, 2017, the indexed debt securities liability was $776 million. During the three and nine months ended September 30, 2017, there was a loss of $36 million and $59 million, respectively, on the indexed debt securities.

Estimated Fair Value of Financial Instruments

The fair values of cash and cash equivalents, investments in debt and equity securities classified as “trading” and short-term borrowings are estimated to be approximately equivalent to carrying amounts and have been excluded from the table below. The carrying amounts of non-trading derivative assets and liabilities and CenterPoint Energy’s ZENS indexed debt securities derivative are stated at fair value and are excluded from the table below. The fair value of each debt instrument is determined by multiplying the principal amount of each debt instrument by a combination of historical trading prices and comparable issue data. These liabilities, which are not measured at fair value in the Condensed Consolidated Balance Sheets, but for which the fair value is disclosed, would be classified as Level 2 in the fair value hierarchy.



	September 30, 2017				December 31, 2016
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)
Financial liabilities:
Long-term debt	$	8,513	$	9,005	$	8,443	$	8,846

(8) Unconsolidated Affiliate

CenterPoint Energy has the ability to significantly influence the operating and financial policies of Enable, a publicly traded MLP, and, accordingly, accounts for its investment in Enable’s common units using the equity method of accounting.

CenterPoint Energy’s maximum exposure to loss related to Enable, a VIE in which CenterPoint Energy is not the primary beneficiary, is limited to its equity investment and Series A Preferred Unit investment as presented in the Condensed Consolidated Balance Sheets as of September 30, 2017 and outstanding current accounts receivable from Enable.

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Transactions with Enable:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(in millions)
Reimbursement of transition services (1)	$	—	$	1	$	3	$	6
Natural gas expenses, including transportation and storage costs	23		22		80		79
Interest income related to notes receivable from Enable	—		—		—		1


(1)	Represents amounts billed under the Transition Agreements for certain support services provided to Enable. Actual transition services costs are recorded net of reimbursement.



	September 30, 2017		December 31, 2016
	(in millions)
Accounts receivable for amounts billed for transition services	$	1	$	1
Accounts payable for natural gas purchases from Enable	8		10

Limited Partner Interest in Enable (1):



	September 30, 2017
CenterPoint Energy	54.1	%
OGE	25.7	%


(1)	Excluding the Series A Preferred Units owned by CenterPoint Energy.

In November 2016, Enable completed a public offering of 11,500,000 common units of which 1,424,281 were sold by ArcLight Capital Partners, LLC. The common units issued and sold by Enable resulted in dilution of both CenterPoint Energy’s and OGE’s limited partner interest in Enable.

Enable Common Units and Series A Preferred Units Held:



	September 30, 2017
	Common	Series A Preferred
CenterPoint Energy	233,856,623	14,520,000
OGE	110,982,805	—

The 139,704,916 subordinated units previously owned by CERC Corp. converted into common units of Enable on a one-for-one basis, on August 30, 2017, at the end of the subordination period, as set forth in Enable’s Fourth Amended and Restated Agreement of Limited Partnership. Upon conversion, holders of common units resulting from the conversion of subordinated units have all the rights and obligations of unitholders holding all other common units, including the right to receive distributions pro rata made with respect to common units.

Generally, sales of more than 5% of the aggregate of the common units CenterPoint Energy owns in Enable or sales by OGE of more than 5% of the aggregate of the common units it owns in Enable are subject to mutual rights of first offer and first refusal.

Enable is controlled jointly by CERC Corp. and OGE, and each own 50% of the management rights in the general partner of Enable. Sale of CenterPoint Energy’s or OGE’s ownership interests in Enable’s general partner to a third party is subject to mutual rights of first offer and first refusal, and CenterPoint Energy is not permitted to dispose of less than all of its interest in Enable’s general partner.

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Summarized unaudited consolidated income information for Enable is as follows:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(in millions)
Operating revenues	$	705	$	620	$	1,997	$	1,658
Cost of sales, excluding depreciation and amortization	349		268		936		717
Impairment of goodwill and other long-lived assets	—		8		—		8
Operating income	137		139		399		299
Net income attributable to Enable	104		110		301		231
Reconciliation of Equity in Earnings, net:
CenterPoint Energy’s interest	$	56	$	61	$	163	$	128
Basis difference amortization (1)	12		12		36		36
CenterPoint Energy’s equity in earnings, net	$	68	$	73	$	199	$	164

(1)

Equity in earnings of unconsolidated affiliates includes CenterPoint Energy’s share of Enable’s earnings adjusted for the amortization of the basis difference of CenterPoint Energy’s original investment in Enable and its underlying equity in Enable’s net assets. The basis difference is amortized over approximately 33 years, the average life of the assets to which the basis difference is attributed.

Summarized unaudited consolidated balance sheet information for Enable is as follows:



	September 30, 2017			December 31, 2016
	(in millions)
Current assets	$	446		$	396
Non-current assets	10,816			10,816
Current liabilities	831			362
Non-current liabilities	2,740			3,056
Non-controlling interest	12			12
Preferred equity	362			362
Enable partners’ equity	7,317			7,420
Reconciliation of Equity Method Investment in Enable:
CenterPoint Energy’s ownership interest in Enable partners’ capital	$	4,007		$	4,067
CenterPoint Energy’s basis difference	(1,526		)	(1,562		)
CenterPoint Energy’s equity method investment in Enable	$	2,481		$	2,505

Distributions Received from Unconsolidated Affiliate:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(in millions)
Investment in Enable’s common units	$	74	$	74	$	223	$	223
Investment in Enable’s Series A Preferred Units	9		9		27		13

As of September 30, 2017, CERC Corp. and OGE also own 40% and 60%, respectively, of the incentive distribution rights held by the general partner of Enable. Enable is expected to pay a minimum quarterly distribution of $0.2875 per common unit on its outstanding common units to the extent it has sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to its general partner and its affiliates, within 60 days after the end of each quarter. If cash distributions to Enable’s unitholders exceed $0.330625 per common unit in any quarter, the general partner will receive increasing percentages or incentive distributions rights, up to 50%, of the cash Enable distributes in excess of that amount. In certain circumstances the general partner of Enable will have the right to reset the minimum quarterly distribution and the target

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distribution levels at which the incentive distributions receive increasing percentages to higher levels based on Enable’s cash distributions at the time of the exercise of this reset election. To date, no incentive distributions have been made.

(9) Goodwill

Goodwill by reportable business segment as of December 31, 2016 and changes in the carrying amount of goodwill as of September 30, 2017 are as follows:



	December 31, 2016			AEM Acquisition (1)		September 30, 2017
	(in millions)
Natural Gas Distribution	$	746		$	—	$	746
Energy Services	105		(2)	5		110		(2)
Other Operations	11			—		11
Total	$	862		$	5	$	867

(1) See Note 3.

(2) Amount presented is net of the accumulated goodwill impairment charge of $252 million recorded in 2012.

CenterPoint Energy performs its goodwill impairment tests at least annually and evaluates goodwill when events or changes in circumstances indicate that its carrying value may not be recoverable. The impairment evaluation for goodwill is performed using a two-step process. In the first step, the fair value of each reporting unit is compared with the carrying amount of the reporting unit, including goodwill. The estimated fair value of the reporting unit is generally determined on the basis of discounted cash flows. If the estimated fair value of the reporting unit is less than the carrying amount of the reporting unit, then a second step must be completed to determine the amount of the goodwill impairment that should be recorded. In the second step, the implied fair value of the reporting unit’s goodwill is determined by allocating the reporting unit’s fair value to all of its assets and liabilities other than goodwill (including any unrecognized intangible assets) in a manner similar to a purchase price allocation. The resulting implied fair value of the goodwill that results from the application of this second step is then compared to the carrying amount of the goodwill and an impairment charge is recorded for the difference.

CenterPoint Energy performed its annual impairment test in the third quarter of 2017 and determined, based on the results of the first step, that no impairment charge was required for any reportable segment.

(10) Indexed Debt Securities (ZENS) and Securities Related to ZENS

(a) Investment in Securities Related to ZENS

In 1995, CenterPoint Energy sold a cable television subsidiary to TW and received TW securities as partial consideration. A subsidiary of CenterPoint Energy now holds 7.1 million shares of TW Common, 0.9 million shares of Time Common and 0.9 million shares of Charter Common, which are classified as trading securities and are expected to be held to facilitate CenterPoint Energy’s ability to meet its obligation under the ZENS. Unrealized gains and losses resulting from changes in the market value of the TW Securities are recorded in CenterPoint Energy’s Condensed Statements of Consolidated Income.

(b) ZENS

In September 1999, CenterPoint Energy issued ZENS having an original principal amount of $1 billion of which $828 million remain outstanding as of September 30, 2017. Each ZENS was originally exchangeable at the holder’s option at any time for an amount of cash equal to 95% of the market value of the reference shares of TW Common attributable to such note. The number and identity of the reference shares attributable to each ZENS are adjusted for certain corporate events. As of September 30, 2017, the reference shares for each ZENS consisted of 0.5 share of TW Common, 0.0625 share of Time Common and 0.061382 share of Charter Common, and the contingent principal balance was $507 million.

On October 22, 2016, AT&T announced that it had entered into a definitive agreement to acquire TW in a stock and cash transaction. On February 15, 2017, TW shareholders approved the announced transaction with AT&T. Pursuant to the merger agreement, upon closing of the merger, TW shareholders would receive for each of their shares of TW Common an estimated implied value of $107.50, comprised of $53.75 per share in cash and $53.75 per share in AT&T Common. The stock portion will be subject to a collar such that TW shareholders will receive 1.437 shares of AT&T Common if AT&T Common’s average stock price is below $37.411 at closing and 1.3 shares of AT&T Common if AT&T Common’s average stock price is above $41.349 at

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closing. Cash received for the TW Common reference shares would subsequently be distributed to ZENS holders, which is expected to reduce the contingent principal balance, and reference shares would consist of Charter Common, Time Common and AT&T Common. AT&T has publicly announced that the merger is expected to close by the end of 2017.

(11) Short-term Borrowings and Long-term Debt


(a)	Short-term Borrowings

Inventory Financing. NGD currently has AMAs associated with its utility distribution service in Arkansas, north Louisiana and Oklahoma that extend through 2020. Pursuant to the provisions of the agreements, NGD sells natural gas and agrees to repurchase an equivalent amount of natural gas during the winter heating seasons at the same cost, plus a financing charge. These transactions are accounted for as an inventory financing and had an associated principal obligation of $48 million and $35 million as of September 30, 2017 and December 31, 2016, respectively.


(b)	Long-term Debt

Debt Retirements. In February 2017, CenterPoint Energy retired $250 million aggregate principal amount of its 5.95% senior notes at their maturity. The retirement of senior notes was financed by the issuance of commercial paper.

Debt Issuances. During the nine months ended September 30, 2017, CenterPoint Energy, Houston Electric and CERC Corp. issued the following debt instruments:



	Issuance Date	Debt Instrument	Aggregate Principal Amount		Interest Rate	Maturity Date
			(in millions)
Houston Electric	January 2017	General mortgage bonds	$	300	3.00%	2027
CenterPoint Energy	August 2017	Unsecured senior notes	500		2.50%	2022
CERC Corp.	August 2017	Unsecured senior notes	300		4.10%	2047

The proceeds from the issuances were used for general limited liability company and corporate purposes, as applicable, including to repay portions of outstanding commercial paper.

Credit Facilities. In June 2017, CenterPoint Energy, Houston Electric and CERC Corp. each entered into amendments to their respective revolving credit facilities to extend the termination date thereof from March 3, 2021 to March 3, 2022 and to terminate the swingline loan subfacility thereunder. The amendments to the CenterPoint Energy and CERC Corp. revolving credit facilities also increased the aggregate commitments by $100 million and $300 million, respectively, to $1.7 billion and $900 million under their respective revolving credit facilities. No changes were made to the aggregate commitments under the Houston Electric revolving credit facility. In connection with the amendments to increase the aggregate commitments under their respective revolving credit facilities, CenterPoint Energy and CERC Corp. each increased the size of their respective commercial paper programs to permit the issuance of commercial paper notes in an aggregate principal amount not to exceed $1.7 billion and $900 million, respectively, at any time outstanding.

As of September 30, 2017 and December 31, 2016, CenterPoint Energy, Houston Electric and CERC Corp. had the following revolving credit facilities and utilization of such facilities:



	September 30, 2017									December 31, 2016
	Size of Facility		Loans		Letters of Credit		Commercial Paper			Size of Facility		Loans		Letters of Credit		Commercial Paper
	(in millions)
CenterPoint Energy	$	1,700	$	—	$	6	$	447	(1)	$	1,600	$	—	$	6	$	835	(1)
Houston Electric	300		—		4		—			300		—		4		—
CERC Corp.	900		—		—		529		(2)	600		—		4		569		(2)
Total	$	2,900	$	—	$	10	$	976		$	2,500	$	—	$	14	$	1,404


(1)	Weighted average interest rate was 1.42% and 1.04% as of September 30, 2017 and December 31, 2016, respectively.


(2)	Weighted average interest rate was 1.43% and 1.03% as of September 30, 2017 and December 31, 2016, respectively.

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Execution Date	Company	Size of Facility			Draw Rate of LIBOR plus (2)	Financial Covenant Limit on Debt for Borrowed Money to Capital Ratio		Debt for Borrowed Money to Capital Ratio as of September 30, 2017 (3)	Termination Date (5)
		(in millions)
March 3, 2016	CenterPoint Energy	$	1,700	(1)	1.250%	65%	(4)	56.9%	March 3, 2022
March 3, 2016	Houston Electric	300			1.125%	65%	(4)	49.0%	March 3, 2022
March 3, 2016	CERC Corp.	900		(1)	1.250%	65%		38.6%	March 3, 2022


(1)	Amended on June 16, 2017 to increase the aggregate commitment size as noted above.


(2)	Based on current credit ratings.


(3)	As defined in the revolving credit facility agreement, excluding Securitization Bonds.

(4)

The financial covenant limit will temporarily increase from 65% to 70% if Houston Electric experiences damage from a natural disaster in its service territory and CenterPoint Energy certifies to the administrative agent that Houston Electric has incurred system restoration costs reasonably likely to exceed $100 million in a consecutive 12-month period, all or part of which Houston Electric intends to seek to recover through securitization financing. Such temporary increase in the financial covenant would be in effect from the date CenterPoint Energy delivers its certification until the earliest to occur of (i) the completion of the securitization financing, (ii) the first anniversary of CenterPoint Energy’s certification or (iii) the revocation of such certification.


(5)	Amended on June 16, 2017 to extend the termination date as noted above.

CenterPoint Energy, Houston Electric and CERC Corp. were in compliance with all financial debt covenants as of September 30, 2017.

(12) Income Taxes

The effective tax rate reported for the three months ended September 30, 2017 was 37% compared to 35% for the same period in 2016. The higher effective tax rate for the three months ended September 30, 2017 was primarily due to the tax effects of receiving less nontaxable income in the period. The effective tax rate reported for the nine months ended September 30, 2017 was 36% compared to 37% for the same period in 2016.

CenterPoint Energy reported no uncertain tax liability as of September 30, 2017 and expects no significant change to the uncertain tax liability over the next twelve months. Tax years through 2015 have been audited and settled with the IRS. For the 2016 and 2017 tax years, CenterPoint Energy is a participant in the IRS’s Compliance Assurance Process.

(13) Commitments and Contingencies


(a)	Natural Gas Supply Commitments

Natural gas supply commitments include natural gas contracts related to CenterPoint Energy’s Natural Gas Distribution and Energy Services business segments, which have various quantity requirements and durations, that are not classified as non-trading derivative assets and liabilities in CenterPoint Energy’s Condensed Consolidated Balance Sheets as of September 30, 2017 and December 31, 2016 as these contracts meet an exception as “normal purchases contracts” or do not meet the definition of a derivative. Natural gas supply commitments also include natural gas transportation contracts that do not meet the definition of a derivative.

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As of September 30, 2017, minimum payment obligations for natural gas supply commitments are approximately:



	(in millions)
Remaining three months of 2017	$	169
2018	507
2019	348
2020	166
2021	76
2022 and beyond	113


(b)	Legal, Environmental and Other Matters

Legal Matters

Gas Market Manipulation Cases. CenterPoint Energy, Houston Electric or their predecessor, Reliant Energy, and certain of their former subsidiaries have been named as defendants in certain lawsuits described below. Under a master separation agreement between CenterPoint Energy and a former subsidiary, RRI, CenterPoint Energy and its subsidiaries are entitled to be indemnified by RRI and its successors for any losses, including certain attorneys’ fees and other costs, arising out of these lawsuits. In May 2009, RRI sold its Texas retail business to a subsidiary of NRG and RRI changed its name to RRI Energy, Inc. In December 2010, Mirant Corporation merged with and became a wholly-owned subsidiary of RRI, and RRI changed its name to GenOn. In December 2012, NRG acquired GenOn through a merger in which GenOn became a wholly-owned subsidiary of NRG. None of the sale of the retail business, the merger with Mirant Corporation, or the acquisition of GenOn by NRG alters RRI’s (now GenOn’s) contractual obligations to indemnify CenterPoint Energy and its subsidiaries, including Houston Electric, for certain liabilities, including their indemnification obligations regarding the gas market manipulation litigation.

A large number of lawsuits were filed against numerous gas market participants in a number of federal and western state courts in connection with the operation of the natural gas markets in 2000–2002. CenterPoint Energy and its affiliates have since been released or dismissed from all such cases. CES, a subsidiary of CERC Corp., was a defendant in a case now pending in federal court in Nevada alleging a conspiracy to inflate Wisconsin natural gas prices in 2000–2002. On May 24, 2016, the district court granted CES’s motion for summary judgment, dismissing CES from the case. The plaintiffs have appealed that ruling. CenterPoint Energy and CES intend to continue vigorously defending against the plaintiffs’ claims. In June 2017, GenOn and various affiliates filed for protection under Chapter 11 of the U.S. Bankruptcy Code. CenterPoint Energy, CERC, and CES submitted proofs of claim in the bankruptcy proceedings to protect their indemnity rights. If GenOn were unable to meet its indemnity obligations or satisfy a liability that has been assumed in the gas market manipulation litigation, then CenterPoint Energy, Houston Electric or CERC could incur liability and be responsible for satisfying the liability. CenterPoint Energy does not expect the ultimate outcome of the case against CES to have a material adverse effect on its financial condition, results of operations or cash flows.

Minnehaha Academy. On August 2, 2017, a natural gas explosion occurred at the Minnehaha Academy in Minneapolis, Minnesota, resulting in the deaths of two school employees, serious injuries to others and significant property damage to the school. CenterPoint Energy, certain of its subsidiaries, and the contractor company working in the school have been named in litigation arising out of this incident. Additionally, CenterPoint Energy is cooperating with ongoing investigations conducted by the National Transportation Safety Board, the Minnesota Occupational Safety and Health Administration and the Minnesota Office of Pipeline Safety. CenterPoint Energy’s general and excess liability insurance policies provide coverage for third party bodily injury and property damage claims.

Environmental Matters

MGP Sites. CERC and its predecessors operated MGPs in the past. With respect to certain Minnesota MGP sites, CERC has completed state-ordered remediation and continues state-ordered monitoring and water treatment. As of September 30, 2017, CERC had a recorded liability of $7 million for continued monitoring and any future remediation required by regulators in Minnesota. The estimated range of possible remediation costs for the sites for which CERC believes it may have responsibility was $4 million to $30 million based on remediation continuing for 30 to 50 years. The cost estimates are based on studies of a site or industry average costs for remediation of sites of similar size. The actual remediation costs will depend on the number of sites to be remediated, the participation of other PRPs, if any, and the remediation methods used.

In addition to the Minnesota sites, the Environmental Protection Agency and other regulators have investigated MGP sites that were owned or operated by CERC or may have been owned by one of its former affiliates. CenterPoint Energy does not expect the ultimate outcome of these matters to have a material adverse effect on the financial condition, results of operations or cash flows of either CenterPoint Energy or CERC.

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Asbestos. Some facilities owned by CenterPoint Energy or its predecessors contain or have contained asbestos insulation and other asbestos-containing materials. CenterPoint Energy and its subsidiaries are from time to time named, along with numerous others, as defendants in lawsuits filed by a number of individuals who claim injury due to exposure to asbestos, and CenterPoint Energy anticipates that additional claims may be asserted in the future. Although their ultimate outcome cannot be predicted at this time, CenterPoint Energy does not expect these matters, either individually or in the aggregate, to have a material adverse effect on CenterPoint Energy’s financial condition, results of operations or cash flows.

Other Environmental. From time to time, CenterPoint Energy identifies the presence of environmental contaminants during its operations or on property where its predecessor companies have conducted operations. Other such sites involving contaminants may be identified in the future. CenterPoint Energy has and expects to continue to remediate identified sites consistent with its legal obligations. From time to time CenterPoint Energy has received notices from regulatory authorities or others regarding its status as a PRP in connection with sites found to require remediation due to the presence of environmental contaminants. In addition, CenterPoint Energy has been named from time to time as a defendant in litigation related to such sites. Although the ultimate outcome of such matters cannot be predicted at this time, CenterPoint Energy does not expect these matters, either individually or in the aggregate, to have a material adverse effect on CenterPoint Energy’s financial condition, results of operations or cash flows.

Other Proceedings

CenterPoint Energy is involved in other legal, environmental, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business. From time to time, CenterPoint Energy is also a defendant in legal proceedings with respect to claims brought by various plaintiffs against broad groups of participants in the energy industry. Some of these proceedings involve substantial amounts. CenterPoint Energy regularly analyzes current information and, as necessary, provides accruals for probable and reasonably estimable liabilities on the eventual disposition of these matters. CenterPoint Energy does not expect the disposition of these matters to have a material adverse effect on CenterPoint Energy’s financial condition, results of operations or cash flows.

(14) Earnings Per Share

The following table reconciles numerators and denominators of CenterPoint Energy’s basic and diluted earnings per share calculations:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(in millions, except share and per share amounts)
Net income	$	169	$	179	$	496	$	331

Basic weighted average shares outstanding	431,026,000		430,682,000		430,939,000		430,581,000
Plus: Incremental shares from assumed conversions:
Restricted stock	3,060,000		2,714,000		3,060,000		2,714,000
Diluted weighted average shares	434,086,000		433,396,000		433,999,000		433,295,000

Basic earnings per share
Net income	$	0.39	$	0.42	$	1.15	$	0.77

Diluted earnings per share
Net income	$	0.39	$	0.41	$	1.14	$	0.76

(15) Reportable Business Segments

CenterPoint Energy’s determination of reportable business segments considers the strategic operating units under which CenterPoint Energy manages sales, allocates resources and assesses performance of various products and services to wholesale or retail customers in differing regulatory environments. CenterPoint Energy uses operating income as the measure of profit or loss for its business segments other than Midstream Investments, where it uses equity in earnings of unconsolidated affiliates.

CenterPoint Energy’s reportable business segments include the following: Electric Transmission & Distribution, Natural Gas Distribution, Energy Services, Midstream Investments and Other Operations. The electric transmission and distribution function

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(Houston Electric) is reported in the Electric Transmission & Distribution business segment. Natural Gas Distribution consists of intrastate natural gas sales to, and natural gas transportation and distribution for, residential, commercial, industrial and institutional customers. Energy Services represents CenterPoint Energy’s non-rate regulated gas sales and services operations. Midstream Investments consists of CenterPoint Energy’s equity investment in Enable (excluding the Series A Preferred Units). Other Operations consists primarily of other corporate operations which support all of CenterPoint Energy’s business operations.

Financial data for business segments is as follows:



	For the Three Months Ended September 30, 2017
	Revenues from External Customers			Net Intersegment Revenues			Operating Income
	(in millions)
Electric Transmission & Distribution	$	843	(1)	$	—		$	247
Natural Gas Distribution	390			8			19
Energy Services	861			10			7
Midstream Investments (2)	—			—			—
Other Operations	4			—			6
Eliminations	—			(18		)	—
Consolidated	$	2,098		$	—		$	279



	For the Three Months Ended September 30, 2016
	Revenues from External Customers			Net Intersegment Revenues			Operating Income
	(in millions)
Electric Transmission & Distribution	$	908	(1)	$	—		$	257
Natural Gas Distribution	370			7			22
Energy Services	608			6			5
Midstream Investments (2)	—			—			—
Other Operations	3			—			—
Eliminations	—			(13		)	—
Consolidated	$	1,889		$	—		$	284



	For the Nine Months Ended September 30, 2017
	Revenues from External Customers			Net Intersegment Revenues			Operating Income		Total Assets as of September 30, 2017
	(in millions)
Electric Transmission & Distribution	$	2,234	(1)	$	—		$	489	$	10,289
Natural Gas Distribution	1,767			24			220		6,067
Energy Services	2,964			34			58		1,337
Midstream Investments (2)	—			—			—		2,481
Other Operations	11			—			9		2,694			(3)
Eliminations	—			(58		)	—		(733		)
Consolidated	$	6,976		$	—		$	776	$	22,135

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	For the Nine Months Ended September 30, 2016
	Revenues from External Customers			Net Intersegment Revenues			Operating Income		Total Assets as of December 31, 2016
	(in millions)
Electric Transmission & Distribution	$	2,331	(1)	$	—		$	498	$	10,211
Natural Gas Distribution	1,672			21			202		6,099
Energy Services	1,433			17			11		1,102
Midstream Investments (2)	—			—			—		2,505
Other Operations	11			—			5		2,681			(3)
Eliminations	—			(38		)	—		(769		)
Consolidated	$	5,447		$	—		$	716	$	21,829


(1)	Electric Transmission & Distribution revenues from major customers are as follows:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(in millions)
Affiliates of NRG	$	221	$	223	$	540	$	527
Affiliates of Vistra Energy Corp.	72		71		172		166


(2)	Midstream Investments’ equity earnings are as follows:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(in millions)
Enable	$	68	$	73	$	199	$	164


(3)	Included in total assets of Other Operations as of September 30, 2017 and December 31, 2016 are pension and other postemployment-related regulatory assets of $715 million and $759 million, respectively.

(16) Subsequent Events

On October 25, 2017, CenterPoint Energy’s board of directors declared a regular quarterly cash dividend of $0.2675 per share of common stock payable on December 8, 2017, to shareholders of record as of the close of business on November 16, 2017.

On October 31, 2017, Enable declared a quarterly cash distribution of $0.318 per unit on all of its outstanding common units for the quarter ended September 30, 2017. Accordingly, CERC Corp. expects to receive a cash distribution of approximately $74 million from Enable in the fourth quarter of 2017 to be made with respect to CERC Corp.’s investment in common units of Enable for the third quarter of 2017.

On October 31, 2017, Enable declared a quarterly cash distribution of $0.625 per Series A Preferred Unit for the quarter ended September 30, 2017. Accordingly, CenterPoint Energy expects to receive a cash distribution of approximately $9 million from Enable in the fourth quarter of 2017 to be made with respect to CenterPoint Energy’s investment in Series A Preferred Units of Enable for the third quarter of 2017.

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Item 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS OF CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

The following discussion and analysis should be read in combination with our Interim Condensed Financial Statements contained in this Form 10-Q and our 2016 Form 10-K.

RECENT EVENTS

Hurricane Harvey. Houston Electric’s electric delivery system and CERC Corp.’s NGD suffered damage as a result of Hurricane Harvey, which struck the Texas coast on Friday, August 25, 2017. For further information regarding the impact of Hurricane Harvey, see Note 5 to our Interim Condensed Financial Statements.

Regulatory Proceedings. For details related to our pending and completed regulatory proceedings to date in 2017, see “—Liquidity and Capital Resources —Regulatory Matters” below.

Debt Issuances. In August 2017, CenterPoint Energy issued $500 million aggregate principal amount of unsecured senior notes and CERC Corp. issued $300 million aggregate principal amount of unsecured senior notes. For further information about our 2017 debt issuances, see Note 11 to our Interim Condensed Financial Statements.

CONSOLIDATED RESULTS OF OPERATIONS



	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(in millions, except per share amounts)
Revenues	$	2,098		$	1,889		$	6,976		$	5,447
Expenses	1,819			1,605			6,200			4,731
Operating Income	279			284			776			716
Interest and Other Finance Charges	(80		)	(83		)	(235		)	(256		)
Interest on Securitization Bonds	(18		)	(23		)	(58		)	(70		)
Equity in Earnings of Unconsolidated Affiliate, net	68			73			199			164
Other Income, net	18			25			95			(30		)
Income Before Income Taxes	267			276			777			524
Income Tax Expense	98			97			281			193
Net Income	$	169		$	179		$	496		$	331

Basic Earnings Per Share	$	0.39		$	0.42		$	1.15		$	0.77

Diluted Earnings Per Share	$	0.39		$	0.41		$	1.14		$	0.76

Three months ended September 30, 2017 compared to three months ended September 30, 2016

We reported net income of $169 million ($0.39 per diluted share) for the three months ended September 30, 2017 compared to net income of $179 million ($0.41 per diluted share) for the three months ended September 30, 2016.

The decrease in net income of $10 million was primarily due to the following key factors:


•	a $40 million decrease in the gain on marketable securities included in Other Income, net shown above;


•	a $5 million decrease in operating income discussed below by segment;


•	a $5 million decrease in equity earnings from our investment in Enable, discussed further in Note 8 to our Interim Condensed Financial Statements; and


•	a $3 million decrease in miscellaneous other non-operating income included in Other Income, net shown above.

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


•	a $36 million decrease in the loss on the underlying value of the indexed debt securities related to the ZENS included in Other Income, net shown above;


•	a $5 million decrease in interest expense related to lower outstanding balances of our Securitization Bonds; and


•	a $3 million decrease in interest expense due to lower weighted average interest rates on outstanding debt.

Nine months ended September 30, 2017 compared to nine months ended September 30, 2016

We reported net income of $496 million ($1.14 per diluted share) for the nine months ended September 30, 2017 compared to net income of $331 million ($0.76 per diluted share) for the nine months ended September 30, 2016.

The increase in net income of $165 million was primarily due to the following key factors:


•	a $199 million decrease in the loss on indexed debt securities related to the ZENS included in Other Income, net shown above, resulting from decreased losses of $82 million in the underlying value of the indexed debt securities and a loss of $117 million from the Charter merger in 2016;


•	a $60 million increase in operating income discussed below by segment;


•	a $35 million increase in equity earnings from our investment in Enable, discussed further in Note 8 to our Interim Condensed Financial Statements;


•	a $21 million decrease in interest expense due to lower weighted average interest rates on outstanding debt;


•	a $14 million increase in cash distributions on Series A Preferred Units included in Other Income, net shown above; and


•	a $12 million decrease in interest expense related to lower outstanding balances of our Securitization Bonds.

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


•	an $88 million increase in income tax expense due to higher net income;


•	an $83 million decrease in the gain on marketable securities included in Other Income, net shown above; and


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

Income Tax Expense

Our effective tax rate reported for the three months ended September 30, 2017 was 37% compared to 35% for the same period in 2016. The higher effective tax rate for the three months ended September 30, 2017 was primarily due to the tax effects of receiving less nontaxable income in the period. The effective tax rate reported for the nine months ended September 30, 2017 was 36% compared to 37% for the same period in 2016. We expect our annual effective tax rate for the fiscal year ending December 31, 2017 to be approximately 36%.

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RESULTS OF OPERATIONS BY BUSINESS SEGMENT

The following table presents operating income for each of our business segments for the three and nine months ended September 30, 2017 and 2016. Included in revenues are intersegment sales. We account for intersegment sales as if the sales were to third parties at current market prices.



	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(in millions)
Electric Transmission & Distribution	$	247	$	257	$	489	$	498
Natural Gas Distribution	19		22		220		202
Energy Services	7		5		58		11
Other Operations	6		—		9		5
Total Consolidated Operating Income	$	279	$	284	$	776	$	716

Electric Transmission & Distribution

For information regarding factors that may affect the future results of operations of our Electric Transmission & Distribution business segment, please read “Risk Factors — Risk Factors Associated with Our Consolidated Financial Condition,” “— Risk Factors Affecting Our Electric Transmission & Distribution Business” and “— Other Risk Factors Affecting Our Businesses or Our Interests in Enable Midstream Partners, LP” in Item 1A of Part I of our 2016 Form 10-K.

The following table provides summary data of our Electric Transmission & Distribution business segment for the three and nine months ended September 30, 2017 and 2016:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(in millions, except throughput and customer data)
Revenues:
TDU	$	729	$	725	$	1,944	$	1,881
Bond Companies	114		183		290		450
Total revenues	843		908		2,234		2,331
Expenses:
Operation and maintenance, excluding Bond Companies	344		336		1,040		995
Depreciation and amortization, excluding Bond Companies	97		96		296		285
Taxes other than income taxes	59		59		177		173
Bond Companies	96		160		232		380
Total expenses	596		651		1,745		1,833
Operating Income	$	247	$	257	$	489	$	498
Operating Income:
TDU	$	229	$	234	$	431	$	428
Bond Companies (1)	18		23		58		70
Total segment operating income	$	247	$	257	$	489	$	498
Throughput (in GWh):
Residential	10,419		10,776		23,512		23,427
Total	26,453		26,518		67,956		66,839
Number of metered customers at end of period:
Residential	2,156,624		2,116,312		2,156,624		2,116,312
Total	2,435,558		2,389,014		2,435,558		2,389,014


(1)	Represents the amount necessary to pay interest on the Securitization Bonds.

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Three months ended September 30, 2017 compared to three months ended September 30, 2016

Our Electric Transmission & Distribution business segment reported operating income of $247 million for the three months ended September 30, 2017, consisting of $229 million from the TDU and $18 million related to the Bond Companies. For the three months ended September 30, 2016, operating income totaled $257 million, consisting of $234 million from the TDU and $23 million related to the Bond Companies.

TDU operating income decreased $5 million, primarily due to the following key factors:


•	lower usage of $12 million, largely due to a return to more normal weather in 2017;


•	lower equity return of $9 million, primarily related to the annual true-up of transition charges correcting for over-collections that occurred during 2016; and


•	lower miscellaneous revenues, including right-of-way, of $7 million.

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


•	rate increases of $12 million related to distribution capital investments;


•	lower operation and maintenance expenses of $4 million; and


•	customer growth of $9 million from the addition of over 46,000 new customers.

Nine months ended September 30, 2017 compared to nine months ended September 30, 2016

Our Electric Transmission & Distribution business segment reported operating income of $489 million for the nine months ended September 30, 2017, consisting of $431 million from the TDU and $58 million related to the Bond Companies. For the nine months ended September 30, 2016, operating income totaled $498 million, consisting of $428 million from the TDU and $70 million related to the Bond Companies.

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


•	rate increases of $39 million related to distribution capital investments; and


•	customer growth of $26 million from the addition of over 46,000 new customers.

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


•	lower equity return of $22 million, primarily related to the annual true-up of transition charges correcting for over-collections that occurred during 2016;


•	higher depreciation and amortization expense, primarily because of ongoing additions to plant in service, and other taxes of $14 million;


•	lower usage of $14 million;


•	lower miscellaneous revenues, including right-of-way, of $9 million;


•	higher operation and maintenance expenses of $2 million; and


•	increased transmission costs billed by transmission providers of $47 million, which were partially offset by higher transmission-related revenues of $46 million.

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Natural Gas Distribution

For information regarding factors that may affect the future results of operations of our Natural Gas Distribution business segment, please read “Risk Factors — Risk Factors Associated with Our Consolidated Financial Condition,” “— Risk Factors Affecting Our Natural Gas Distribution and Energy Services Businesses” and “— Other Risk Factors Affecting Our Businesses or Our Interests in Enable Midstream Partners, LP” in Item 1A of Part I of our 2016 Form 10-K.

The following table provides summary data of our Natural Gas Distribution business segment for the three and nine months ended September 30, 2017 and 2016:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(in millions, except throughput and customer data)
Revenues	$	398	$	377	$	1,791	$	1,693
Expenses:
Natural gas	117		104		742		679
Operation and maintenance	163		159		531		526
Depreciation and amortization	66		61		194		180
Taxes other than income taxes	33		31		104		106
Total expenses	379		355		1,571		1,491
Operating Income	$	19	$	22	$	220	$	202
Throughput (in Bcf):
Residential	13		12		94		105
Commercial and industrial	50		51		189		193
Total Throughput	63		63		283		298
Number of customers at end of period:
Residential	3,179,284		3,143,357		3,179,284		3,143,357
Commercial and industrial	253,041		251,043		253,041		251,043
Total	3,432,325		3,394,400		3,432,325		3,394,400

Three months ended September 30, 2017 compared to three months ended September 30, 2016

Our Natural Gas Distribution business segment reported operating income of $19 million for the three months ended September 30, 2017 compared to $22 million for the three months ended September 30, 2016.

Operating income decreased $3 million as a result of the following key factors:


•	increased depreciation and amortization expense, primarily due to ongoing additions to plant-in-service, and other taxes of $6 million;


•	lower usage of $4 million, primarily due to the timing of a decoupling normalization adjustment; and


•	higher operation and maintenance expenses of $3 million.

These decreases were partially offset by the following:


•	rate relief increased $5 million, primarily from Texas jurisdictions of $2 million, Arkansas rate case filing of $1 million and Mississippi RRA of $1 million; and


•	customer growth of $2 million associated with the addition of approximately 38,000 new customers.

Increased operation and maintenance expenses related to energy efficiency programs of $1 million were offset by corresponding increases in the related revenues.

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Nine months ended September 30, 2017 compared to nine months ended September 30, 2016

Our Natural Gas Distribution business segment reported operating income of $220 million for the nine months ended September 30, 2017 compared to $202 million for the nine months ended September 30, 2016.

Operating income increased $18 million as a result of the following key factors:


•	rate increases of $25 million, primarily from Texas jurisdictions of $12 million, Arkansas rate case filing of $10 million and Mississippi RRA of $3 million;


•	labor and benefits were favorable by $11 million resulting primarily from the recording of a regulatory asset (and a corresponding reduction in expense) to recover $16 million of prior postretirement expenses in future rates established in the Texas Gulf rate order; and


•	customer growth of $3 million associated with the addition of approximately 38,000 new customers.

These increases were partially offset by the following:


•	increased depreciation and amortization expense, primarily due to ongoing additions to plant-in-service, and other taxes of $10 million;


•	higher operation and maintenance expenses of $9 million partially resulting from an adjustment associated with the Texas Gulf rate order of $4 million, which is timing related; and


•	lower usage of $7 million primarily due to milder weather effects, partially mitigated by decoupling and weather normalization adjustments.

Increased operation and maintenance expenses related to energy efficiency programs of $7 million and increased gross receipts taxes of $2 million were offset by corresponding increases in the related revenues.

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Energy Services

For information regarding factors that may affect the future results of operations of our Energy Services business segment, please read “Risk Factors — Risk Factors Associated with Our Consolidated Financial Condition,” “— Risk Factors Affecting Our Natural Gas Distribution and Energy Services Businesses” and “— Other Risk Factors Affecting Our Businesses or Our Interests in Enable Midstream Partners, LP” in Item 1A of Part I of our 2016 Form 10-K.

The following table provides summary data of our Energy Services business segment for the three and nine months ended September 30, 2017 and 2016:



	Three Months Ended September 30,					Nine Months Ended September 30,
	2017		2016			2017		2016
	(in millions, except throughput and customer data)
Revenues	$	871	$	614		$	2,998	$	1,450
Expenses:
Natural gas	839		591			2,865		1,389
Operation and maintenance	22		16			65		43
Depreciation and amortization	3		1			9		5
Taxes other than income taxes	—		1			1		2
Total expenses	864		609			2,940		1,439
Operating Income	$	7	$	5		$	58	$	11

Timing impacts related to mark-to-market gain (loss) (1)	$	2	$	(2	)	$	23	$	(18	)

Throughput (in Bcf)	272		200			864		570

Number of customers at end of period (2)	30,817		31,669			30,817		31,669


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


(2)	Does not include approximately 66,100 natural gas customers as of September 30, 2017 that are under residential and small commercial choice programs invoiced by their host utility.

Three months ended September 30, 2017 compared to three months ended September 30, 2016

Our Energy Services business segment reported operating income of $7 million for the three months ended September 30, 2017 compared to $5 million for the three months ended September 30, 2016. The increase in operating income of $2 million was primarily due to a $4 million increase from mark-to-market accounting for derivatives associated with certain natural gas purchases and sales used to lock in economic margins. Operating income for the three months ended September 30, 2017 also included $2 million of expenses related to the acquisition and integration of AEM.

Nine months ended September 30, 2017 compared to nine months ended September 30, 2016

Our Energy Services business segment reported operating income of $58 million for the nine months ended September 30, 2017 compared to $11 million for the nine months ended September 30, 2016. The increase in operating income of $47 million was primarily due to a $41 million increase from mark-to-market accounting for derivatives associated with certain natural gas purchases and sales used to lock in economic margins. Operating income in the first nine months of 2017 also included $3 million of expenses related to the acquisition and integration of AEM. The remaining increase in operating income was primarily due to the increased throughput related to the acquisition of AEM in 2017.

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Midstream Investments

For information regarding factors that may affect the future results of operations of our Midstream Investments business segment, please read “Risk Factors — Risk Factors Affecting Our Interests in Enable Midstream Partners, LP” and “— Other Risk Factors Affecting Our Businesses or Our Interests in Enable Midstream Partners, LP” in Item 1A of Part I of our 2016 Form 10-K.

The following table provides pre-tax equity income of our Midstream Investments business segment for the three and nine months ended September 30, 2017 and 2016:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(in millions)
Enable	$	68	$	73	$	199	$	164

Other Operations

The following table shows the operating income of our Other Operations business segment for the three and nine months ended September 30, 2017 and 2016:



	Three Months Ended September 30,					Nine Months Ended September 30,
	2017			2016		2017		2016
	(in millions)
Revenues	$	4		$	3	$	11	$	11
Expenses	(2		)	3		2		6
Operating Income	$	6		$	—	$	9	$	5

CERTAIN FACTORS AFFECTING FUTURE EARNINGS

For information on other developments, factors and trends that may have an impact on our future earnings, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Certain Factors Affecting Future Earnings” in Item 7 of Part II of our 2016 Form 10-K, “Risk Factors” in Item 1A of Part I of our 2016 Form 10-K and “Cautionary Statement Regarding Forward-Looking Information” in this Form 10-Q.

LIQUIDITY AND CAPITAL RESOURCES

Historical Cash Flows

The following table summarizes the net cash provided by (used in) operating, investing and financing activities for the nine months ended September 30, 2017 and 2016:



	Nine Months Ended September 30,
	2017			2016
	(in millions)
Cash provided by (used in):
Operating activities	$	1,031		$	1,455
Investing activities	(892		)	(739		)
Financing activities	(279		)	(710		)

Cash Provided by Operating Activities

Net cash provided by operating activities in the first nine months of 2017 decreased $424 million compared to the first nine months of 2016 due to changes in working capital ($301 million), lower net income after adjusting for non-cash and non-operating items ($116 million; primarily depreciation and amortization) and decreased cash from other non-current items ($7 million). The changes in working capital items in the first nine months of 2017 primarily related to decreased cash provided by taxes receivable; margin deposits, net; net regulatory assets and liabilities; non-trading derivatives, net; and inventory; partially offset by increased

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cash provided by net accounts receivable/payable; interest and taxes accrued; net other current assets and liabilities; and fuel cost recovery.

Cash Used in Investing Activities

Net cash used in investing activities in the first nine months of 2017 increased $153 million compared to the first nine months of 2016 primarily due to decreased cash received for the repayment of notes receivable from Enable ($363 million), decreased proceeds from the sale of marketable securities associated with the Charter merger ($178 million) and increased cash used for acquisitions ($30 million), which were partially offset by decreased cash used for the purchase of Series A Preferred Units ($363 million), decreased capital expenditures ($53 million) and decreased restricted cash ($10 million). In 2017, we acquired AEM for $132 million in cash and, in 2016, we acquired Continuum for $102 million in cash.

Cash Used in Financing Activities

Net cash used in financing activities in the first nine months of 2017 decreased $431 million compared to the first nine months of 2016 due to increased proceeds from long-term debt ($496 million), decreased payments of long-term debt ($258 million), decreased distributions to ZENS holders ($178 million) and increased short-term borrowings ($10 million), which were partially offset by increased payments of commercial paper ($491 million), increased payments of common stock dividends ($14 million) and increased debt issuance costs ($4 million).

Future Sources and Uses of Cash

Our liquidity and capital requirements are affected primarily by our results of operations, capital expenditures, debt service requirements, tax payments, working capital needs and various regulatory actions. Our capital expenditures are expected to be used for investment in infrastructure for our electric transmission and distribution operations and our natural gas distribution operations. These capital expenditures are anticipated to maintain reliability and safety as well as expand our systems through value-added projects. Our principal anticipated cash requirements for the remaining three months of 2017 include the following:


•	capital expenditures of approximately $473 million;


•	maturing senior notes of $250 million;


•	scheduled principal payments on Securitization Bonds of $64 million;


•	restoration costs associated with Hurricane Harvey;


•	dividend payments on CenterPoint Energy, Inc. common stock; and


•	interest payments on debt.

We expect that borrowings under our credit facilities, proceeds from commercial paper and anticipated cash flows from operations and distributions on our investments in common units and Series A Preferred Units from Enable will be sufficient to meet our anticipated cash needs for the remaining three months of 2017. Discretionary financing or refinancing may result in the issuance of equity or debt securities in the capital markets or the arrangement of additional credit facilities. Issuances of equity or debt in the capital markets, funds raised in the commercial paper markets and additional credit facilities may not, however, be available to us on acceptable terms.

Off-Balance Sheet Arrangements

Other than operating leases, we have no off-balance sheet arrangements.

Regulatory Matters

Brazos Valley Connection Project

Construction began on the Brazos Valley Connection in February 2017, and Houston Electric expects to complete construction and energize the Brazos Valley Connection in the first quarter of 2018, ahead of the original June 1, 2018 energization date. Houston Electric continues to anticipate that the final capital costs of the project will be within the estimated range of approximately $270-$310 million in the PUCT’s original order. Houston Electric is eligible to continue making filings for the recovery of land acquisition costs through interim TCOS updates in advance of project completion.

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Freeport Project

In April 2017, Houston Electric submitted a proposal to ERCOT requesting its endorsement of Houston Electric’s approximately $250 million transmission project in the Freeport, Texas area, which includes enhancements to two existing substations and the construction of a new 345 kv double-circuit transmission line. Capital expenditures for the project will be incremental to its previously disclosed five-year capital plan. Houston Electric anticipates a decision from ERCOT in the fourth quarter of 2017, and if approved, will make the necessary filings with the PUCT.

PHMSA Matters

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. Both CERC and Enable own and operate underground storage facilities that are 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. This rule went into effect on January 18, 2017, with an announced compliance deadline of January 18, 2018. PHMSA determined, however, that it will not issue enforcement citations to any operators for violations of provisions of the interim final rule that had previously been non-mandatory provisions of American Petroleum Institute Recommended Practices 1170 and 1171 until one year after PHMSA issues a final rule, which it expects to publish in January of 2018. On October 19, 2017, PHMSA formally reopened the comment period on the interim final rule in response to a petition for reconsideration. This matter remains ongoing and subject to future PHMSA determinations. CERC and Enable will continue to monitor developments and assess the potential impact of any modifications to this rule.

Rate Change Applications

Houston Electric and CERC are routinely involved in rate change applications before state regulatory authorities. Those applications include general rate cases where the entire cost of service of the utility is assessed and reset. In addition, Houston Electric is periodically involved in proceedings to adjust its capital tracking mechanisms (TCOS and DCRF) and annually files to adjust its EECRF. CERC is periodically involved in proceedings to adjust its capital tracking mechanisms in Texas (GRIP), its cost of service adjustments in Arkansas, Louisiana, Mississippi and Oklahoma (FRP, RSP, RRA and PBRC), its decoupling mechanism in Minnesota, and its energy efficiency cost trackers in Arkansas, Minnesota, Mississippi and Oklahoma (EECR, CIP, EECR and EECR). The table below reflects significant applications pending or completed since our 2016 Form 10-K was filed with the SEC.

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Mechanism	Annual Increase (1) (in millions)	Filing Date	Effective Date	Approval Date	Additional Information
Houston Electric (PUCT)
AMS	N/A	June 2017	TBD	TBD	Final reconciliation of AMS surcharge proposing a $28.7 million refund for AMS revenue in excess of expenses, for which a reserve has been recorded. Refunds began in September 2017.
EECRF (2)	$11.0	June 2017	TBD	TBD	Annual reconciliation filing for program year 2016 and includes proposed performance bonus of $11 million. Anticipated effective date of March 2018.
DCRF	41.8	April 2017	September 2017	July 2017	Based on an increase in eligible distribution-invested capital for 2016 of $479 million. Unanimous Stipulation and Settlement Agreement was filed in June 2017 for $86.8 million (a $41.8 million annual increase). The settlement agreement also included the AMS refund referenced above.
TCOS	7.8	December 2016	February 2017	February 2017	Based on an incremental increase in total rate base of $109.6 million.
TCOS	39.3	September 2017	TBD	TBD	Based on an incremental increase in total rate base of $263.4 million.
South Texas and Beaumont/East Texas (Railroad Commission)
GRIP	7.6	March 2017	July 2017	June 2017	Based on net change in invested capital of $46.5 million.
Houston and Texas Coast (Railroad Commission)
Rate Case	16.5	November 2016	May 2017	May 2017	The Railroad Commission approved a unanimous settlement agreement establishing parameters for future GRIP filings, including a 9.6% ROE on a 55.15% equity ratio.
Texarkana, Texas Service Area (Multiple City Jurisdictions)
Rate Case	1.1	July 2017	September 2017	August 2017	Approved rates are consistent with Arkansas rates approved in 2016.
Arkansas (APSC)
EECR (2)	0.5	May 2017	January 2018	September 2017	Recovers $11.0 million, including an incentive of $0.5 million based on 2016 program performance.
FRP	7.6	April 2017	October 2017	September 2017	Based on ROE of 9.5% as approved in the last rate case. Unanimous Settlement Agreement was filed in July 2017 for $7.6 million and was subsequently approved.
BDA	3.9	March 2017	June 2017	June 2017	For the evaluation period between January 2016 and August 2016. Amounts are recorded during the evaluation period.
Minnesota (MPUC)
Rate Case	56.5	August 2017	TBD	TBD	Reflects a proposed 10.0% ROE on a 52.18% equity ratio. Includes a proposal to extend decoupling beyond current expiration date of June 2018. Interim rates reflecting an annual increase of $47.8 million were effective October 1, 2017.
CIP (2)	13.8	May 2017	August 2017	August 2017	Annual reconciliation filing for program year 2016 and includes performance bonus of $13.8 million.
Decoupling	20.4	September 2017	September 2017	TBD	Reflects revenue under recovery for the period July 1, 2016 through June 30, 2017 and $3.0 million related to the under recovery of prior period adjustment factor. $9.2 million was recognized in 2016 and $11.2 million has been recognized in 2017.
Mississippi (MPSC)
RRA	2.3	May 2017	July 2017	July 2017	Authorized ROE of 9.59% and a capital structure of 50% debt and 50% equity.
Louisiana (LPSC)
RSP	1.0	September 2016	December 2016	April 2017	Authorized ROE of 9.95% and a capital structure of 48% debt and 52% equity.
RSP	3.4	September 2017	December 2017	TBD	Authorized ROE of 9.95% and a capital structure of 48% debt and 52% equity.
Oklahoma (OCC)
EECR (2)	0.4	March 2017	November 2017	October 2017	Recovers $2.6 million, including an incentive of $0.4 million based on 2016 program performance.
PBRC	2.2	March 2017	November 2017	October 2017	Based on ROE of 10%.


(1)	Represents proposed increases when effective date and/or approval date is not yet determined. Approved rates could differ materially from proposed rates.


(2)	Amounts are recorded when approved.

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Other Matters

Credit Facilities

Our revolving credit facilities may be drawn on by the companies from time to time to provide funds used for general corporate purposes, including to backstop the companies’ commercial paper programs. The facilities may also be utilized to obtain letters of credit. For further details related to our revolving credit facilities and the 2017 amendments, please see Note 11 to our Interim Condensed Financial Statements.

As of October 26, 2017, we had the following facilities:



Company	Size of Facility		Amount Utilized at October 26, 2017 (1)			Termination Date
(in millions)
CenterPoint Energy	$	1,700	$	403	⁽²⁾	March 3, 2022
Houston Electric	300		4		⁽³⁾	March 3, 2022
CERC Corp.	900		561		⁽⁴⁾	March 3, 2022


(1)	Based on the consolidated debt to capitalization covenant in our revolving credit facility and the revolving credit facility of each of Houston Electric and CERC Corp., we would have been permitted to utilize the full capacity of such revolving credit facilities, which aggregated $2.9 billion as of September 30, 2017.


(2)	Represents outstanding commercial paper of $397 million and outstanding letters of credit of $6 million.


(3)	Represents outstanding letters of credit.


(4)	Represents outstanding commercial paper.

Borrowings under each of the three revolving credit facilities are subject to customary terms and conditions. However, there is no requirement that the borrower make representations prior to borrowings as to the absence of material adverse changes or litigation that could be expected to have a material adverse effect. Borrowings under each of the revolving credit facilities are subject to acceleration upon the occurrence of events of default that we consider customary. The revolving credit facilities also provide for customary fees, including commitment fees, administrative agent fees, fees in respect of letters of credit and other fees. In each of the three revolving credit facilities, the spread to LIBOR and the commitment fees fluctuate based on the borrower’s credit rating. The borrowers are currently in compliance with the various business and financial covenants in the three revolving credit facilities.

Debt Financing Transactions

In January 2017, Houston Electric issued $300 million aggregate principal amount of general mortgage bonds. In February 2017, CenterPoint Energy retired $250 million aggregate principal amount of its 5.95% senior notes at their maturity. In August 2017, CenterPoint Energy issued $500 million aggregate principal amount of unsecured senior notes. In August 2017, CERC Corp. issued $300 million aggregate principal amount of unsecured senior notes. For further information about our 2017 debt transactions, see Note 11 to our Interim Condensed Financial Statements.

Securities Registered with the SEC

On January 31, 2017, CenterPoint Energy, Houston Electric and CERC Corp. filed a joint shelf registration statement with the SEC registering indeterminate principal amounts of Houston Electric’s general mortgage bonds, CERC Corp.’s senior debt securities and CenterPoint Energy’s senior debt securities and junior subordinated debt securities and an indeterminate number of CenterPoint Energy’s shares of common stock, shares of preferred stock, as well as stock purchase contracts and equity units. The joint shelf registration statement will expire on January 31, 2020.

Temporary Investments

As of October 26, 2017, we had no temporary external investments.

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Money Pool

We have a money pool through which the holding company and participating subsidiaries can borrow or invest on a short-term basis. Funding needs are aggregated and external borrowing or investing is based on the net cash position. The net funding requirements of the money pool are expected to be met with borrowings under our revolving credit facility or the sale of our commercial paper.

Impact on Liquidity of a Downgrade in Credit Ratings

The interest on borrowings under our credit facilities is based on our credit rating. On August 4, 2017, S&P revised its rating outlooks on senior debt of CenterPoint Energy, Houston Electric and CERC Corp. to positive from developing and affirmed its ratings. On September 24, 2017, Fitch upgraded Houston Electric’s senior secured debt rating to A+ and maintained its rating outlook of stable. In addition, Fitch revised its rating outlooks on senior debt of CenterPoint Energy and CERC Corp. to positive from stable and affirmed its ratings.

As of October 26, 2017, Moody’s, S&P and Fitch had assigned the following credit ratings to senior debt of CenterPoint Energy and certain subsidiaries:

Moody’s

S&P

Fitch

Company/Instrument

Rating

Outlook (1)

Rating

Outlook (2)

Rating

Outlook (3)

CenterPoint Energy Senior

Unsecured Debt

Baa1

Stable

BBB+

Positive

BBB

Positive

Houston Electric Senior
Secured Debt

Stable

Positive

A+

Stable

CERC Corp. Senior Unsecured

Debt

Baa2

Stable

A-

Positive

BBB

Positive


(1)	A Moody’s rating outlook is an opinion regarding the likely direction of an issuer’s rating over the medium term.


(2)	An S&P rating outlook assesses the potential direction of a long-term credit rating over the intermediate to longer term.


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

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

A decline in credit ratings could increase borrowing costs under our revolving credit facilities. If our credit ratings or those of Houston Electric or CERC Corp. had been downgraded one notch by each of the three principal credit rating agencies from the ratings that existed as of September 30, 2017, the impact on the borrowing costs under the three revolving credit facilities would have been immaterial. A decline in credit ratings would also increase the interest rate on long-term debt to be issued in the capital markets and could negatively impact our ability to complete capital market transactions and to access the commercial paper market. Additionally, a decline in credit ratings could increase cash collateral requirements and reduce earnings of our Natural Gas Distribution and Energy Services business segments.

CES, a wholly-owned subsidiary of CERC Corp. operating in our Energy Services business segment, provides natural gas sales and services primarily to commercial and industrial customers and electric and natural gas utilities throughout the United States. To economically hedge its exposure to natural gas prices, CES uses derivatives with provisions standard for the industry, including those pertaining to credit thresholds. Typically, the credit threshold negotiated with each counterparty defines the amount of unsecured credit that such counterparty will extend to CES. To the extent that the credit exposure that a counterparty has to CES at a particular time does not exceed that credit threshold, CES is not obligated to provide collateral. Mark-to-market exposure in excess of the credit threshold is routinely collateralized or settled-to-market by CES. As of September 30, 2017, the amounts posted as collateral and settled-to-market aggregated approximately $35 million. Should the credit ratings of CERC Corp. (as the credit support provider for CES) fall below certain levels, CES would be required to provide additional collateral up to the amount of its previously unsecured credit limit. We estimate that as of September 30, 2017, unsecured credit limits extended to CES by counterparties aggregated $358 million, and $1 million of such amount was utilized.

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Pipeline tariffs and contracts typically provide that if the credit ratings of a shipper or the shipper’s guarantor drop below a threshold level, which is generally investment grade ratings from both Moody’s and S&P, cash or other collateral may be demanded from the shipper in an amount equal to the sum of three months’ charges for pipeline services plus the unrecouped cost of any lateral built for such shipper. If the credit ratings of CERC Corp. decline below the applicable threshold levels, CERC Corp. might need to provide cash or other collateral of as much as $197 million as of September 30, 2017. The amount of collateral will depend on seasonal variations in transportation levels.

ZENS and Securities Related to ZENS

If our creditworthiness were to drop such that ZENS holders thought our liquidity was adversely affected or the market for the ZENS were to become illiquid, some ZENS holders might decide to exchange their ZENS for cash. Funds for the payment of cash upon exchange could be obtained from the sale of the shares of TW Securities that we own or from other sources. We own shares of TW Securities equal to approximately 100% of the reference shares used to calculate our obligation to the holders of the ZENS. ZENS exchanges result in a cash outflow because tax deferrals related to the ZENS and TW Securities shares would typically cease when ZENS are exchanged or otherwise retired and TW Securities shares are sold. The ultimate tax liability related to the ZENS continues to increase by the amount of the tax benefit realized each year, and there could be a significant cash outflow when the taxes are paid as a result of the retirement of the ZENS. If all ZENS had been exchanged for cash on September 30, 2017, deferred taxes of approximately $472 million would have been payable in 2017. If all the TW Securities had been sold on September 30, 2017, capital gains taxes of approximately $331 million would have been payable in 2017.

For additional information about ZENS, see Note 10 to our Interim Condensed Financial Statements.

Cross Defaults

Under our revolving credit facility, a payment default on, or a non-payment default that permits acceleration of, any indebtedness for borrowed money and certain other specified types of obligations (including guarantees) exceeding $125 million by us or any of our significant subsidiaries will cause a default. A default by CenterPoint Energy would not trigger a default under our subsidiaries’ debt instruments or revolving credit facilities.

Possible Acquisitions, Divestitures and Joint Ventures

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

In February 2016, we 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. We have determined that we will no longer pursue a spin option. Should the sale option not be viable, we intend to reduce our ownership in Enable over time through a sale of the common units we hold in the public equity markets, subject to market conditions. 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.

Enable Midstream Partners

We receive quarterly cash distributions from Enable on its common units and Series A Preferred Units we own. A reduction in the cash distributions we receive from Enable could significantly impact our liquidity. For additional information about cash distributions from Enable, see Notes 8 and 16 to our Interim Condensed Financial Statements.

Hedging of Interest Expense for Future Debt Issuances

During the first three quarters of 2017, we entered into forward interest rate agreements to hedge, in part, volatility in the U.S. treasury rates by reducing variability in cash flows related to interest payments. For further information, see Note 6(a) to our Interim Condensed Financial Statements.

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Weather Hedge

We have entered into partial weather hedges for certain NGD jurisdictions and Houston Electric’s service territory to mitigate the impact of fluctuations from normal weather. We remain exposed to some weather risk as a result of the partial hedges. For more information about our weather hedges, see Note 6(a) to our Interim Condensed Financial Statements.

Other Factors that Could Affect Cash Requirements

In addition to the above factors, our liquidity and capital resources could be affected by:


•	cash collateral requirements that could exist in connection with certain contracts, including our weather hedging arrangements, and gas purchases, gas price and gas storage activities of our Natural Gas Distribution and Energy Services business segments;


•	acceleration of payment dates on certain gas supply contracts, under certain circumstances, as a result of increased gas prices and concentration of natural gas suppliers;


•	increased costs related to the acquisition of natural gas;


•	increases in interest expense in connection with debt refinancings and borrowings under credit facilities;


•	various legislative or regulatory actions;


•	incremental collateral, if any, that may be required due to regulation of derivatives;


•	the ability of GenOn and its subsidiaries, currently the subject of bankruptcy proceedings, to satisfy their obligations in respect of GenOn’s indemnity obligations to us and our subsidiaries;


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


•	slower customer payments and increased write-offs of receivables due to higher gas prices or changing economic conditions;


•	the outcome of litigation brought by or against us;


•	contributions to pension and postretirement benefit plans;


•	restoration costs and revenue losses resulting from future natural disasters such as hurricanes and the timing of recovery of such restoration costs; and


•	various other risks identified in “Risk Factors” in Item 1A of Part I of our 2016 Form 10-K.

Certain Contractual Limits on Our Ability to Issue Securities and Borrow Money

Houston Electric has contractually agreed that it will not issue additional first mortgage bonds, subject to certain exceptions. For information about the total debt to capitalization financial covenants in our revolving credit facilities, see Note 11 to our Interim Condensed Financial Statements.

NEW ACCOUNTING PRONOUNCEMENTS

See Note 2 to our Interim Condensed Financial Statements, incorporated herein by reference, for a discussion of new accounting pronouncements that affect us.

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Item 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk

As of September 30, 2017, we had outstanding long-term debt, lease obligations and obligations under our ZENS that subject us to the risk of loss associated with movements in market interest rates.

Our floating rate obligations aggregated $976 million and $1.4 billion as of September 30, 2017 and December 31, 2016, respectively. If the floating interest rates were to increase by 10% from September 30, 2017 rates, our combined interest expense would increase by approximately $1.4 million annually.

As of September 30, 2017 and December 31, 2016, we had outstanding fixed-rate debt (excluding indexed debt securities) aggregating $7.6 billion and $7.1 billion, respectively, in principal amount and having a fair value of $8.1 billion and $7.5 billion, respectively. Because these instruments are fixed-rate, they do not expose us to the risk of loss in earnings due to changes in market interest rates. However, the fair value of these instruments would increase by approximately $223 million if interest rates were to decline by 10% from levels at September 30, 2017. In general, such an increase in fair value would impact earnings and cash flows only if we were to reacquire all or a portion of these instruments in the open market prior to their maturity.

The ZENS obligation is bifurcated into a debt component and a derivative component. The debt component of $120 million as of September 30, 2017 was a fixed-rate obligation and, therefore, did not expose us to the risk of loss in earnings due to changes in market interest rates. However, the fair value of the debt component would increase by approximately $18 million if interest rates were to decline by 10% from levels at September 30, 2017. Changes in the fair value of the derivative component, a $776 million recorded liability at September 30, 2017, are recorded in our Condensed Statements of Consolidated Income and, therefore, we are exposed to changes in the fair value of the derivative component as a result of changes in the underlying risk-free interest rate. If the risk-free interest rate were to increase by 10% from September 30, 2017 levels, the fair value of the derivative component liability would increase by approximately $5 million, which would be recorded as an unrealized loss in our Condensed Statements of Consolidated Income.

Equity Market Value Risk

We are exposed to equity market value risk through our ownership of 7.1 million shares of TW Common, 0.9 million shares of Time Common and 0.9 million shares of Charter Common, which we hold to facilitate our ability to meet our obligations under the ZENS. A decrease of 10% from the September 30, 2017 aggregate market value of these shares would result in a net loss of approximately $1 million, which would be recorded as an unrealized loss in our Condensed Statements of Consolidated Income.

Commodity Price Risk From Non-Trading Activities

We use derivative instruments as economic hedges to offset the commodity price exposure inherent in our businesses. The commodity risk created by these instruments, including the offsetting impact on the market value of natural gas inventory, is described below. We measure this commodity risk using a sensitivity analysis. For purposes of this analysis, we estimate commodity price risk by applying a $0.50 change in the forward NYMEX price to our net open fixed price position (including forward fixed price physical contracts, natural gas inventory and fixed price financial contracts) at the end of each period. As of September 30, 2017, the recorded fair value of our non-trading energy derivatives was a net asset of $80 million (before collateral), all of which is related to our Energy Services business segment. A $0.50 change in the forward NYMEX price would have had a combined impact of $3 million on our non-trading energy derivatives net asset and the market value of natural gas inventory.

Commodity price risk is not limited to changes in forward NYMEX prices. Variation of commodity pricing between the different indices used to mark to market portions of our natural gas inventory (Gas Daily) and the related fair value hedge (NYMEX) can result in volatility to our net income. Over time, any gains or losses on the sale of storage gas inventory would be offset by gains or losses on the fair value hedges.


Item 4.	CONTROLS AND PROCEDURES

In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our principal executive officer and principal financial officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of September 30, 2017 to provide assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and

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such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding disclosure.

There has been no change in our internal controls over financial reporting that occurred during the three months ended September 30, 2017 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

PART II. OTHER INFORMATION


Item 1.	LEGAL PROCEEDINGS

For a description of certain legal and regulatory proceedings affecting CenterPoint Energy, please read Note 13(b) to our Interim Condensed Financial Statements and “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Future Sources and Uses of Cash” and “— Regulatory Matters,” each of which is incorporated herein by reference. See also “Business — Regulation” and “— Environmental Matters” in Item 1 and “Legal Proceedings” in Item 3 of our 2016 Form 10-K.


Item 1A.	RISK FACTORS

There have been no material changes from the risk factors disclosed in our 2016 Form 10-K.


Item 5.	OTHER INFORMATION

Ratio of Earnings to Fixed Charges. The ratio of earnings to fixed charges for the nine months ended September 30, 2017 and 2016 was 3.63 and 2.73, respectively. We do not believe that the ratios for these nine-month periods are necessarily indicative of the ratios for the 12-month periods due to the seasonal nature of our business. The ratios were calculated pursuant to applicable rules of the SEC.


Item 6.	EXHIBITS

The following exhibits are filed herewith:

Exhibits not incorporated by reference to a prior filing are designated by a cross (+); all exhibits not so designated are incorporated by reference to a prior filing as indicated.

Agreements included as exhibits are included only to provide information to investors regarding their terms. Agreements listed below may contain representations, warranties and other provisions that were made, among other things, to provide the parties thereto with specified rights and obligations and to allocate risk among them, and no such agreement should be relied upon as constituting or providing any factual disclosures about CenterPoint Energy, Inc., any other persons, any state of affairs or other matters.

Pursuant to Item 601(b)(4)(iii)(A) of Regulation S-K, CenterPoint Energy has not filed as exhibits to this Form 10-Q certain long-term debt instruments, including indentures, under which the total amount of securities authorized does not exceed 10% of the total assets of CenterPoint Energy and its subsidiaries on a consolidated basis. CenterPoint Energy hereby agrees to furnish a copy of any such instrument to the SEC upon request.



Exhibit Number	Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference
3.1	Restated Articles of Incorporation of CenterPoint Energy	CenterPoint Energy’s Form 8-K dated July 24, 2008	1-31447	3.2
3.2	Third Amended and Restated Bylaws of CenterPoint Energy	CenterPoint Energy’s Form 8-K dated February 21, 2017	1-31447	3.1
3.3	Statement of Resolutions Deleting Shares Designated Series A Preferred Stock of CenterPoint Energy	CenterPoint Energy’s Form 10-K for the year ended December 31, 2011	1-31447	3(c)
4.1	Form of CenterPoint Energy Stock Certificate	CenterPoint Energy’s Registration Statement on Form S-4	3-69502	4.1
4.2	$1,600,000,000 Credit Agreement, dated as of March 3, 2016, among CenterPoint Energy, as Borrower, and the banks named therein	CenterPoint Energy’s Form 8-K dated March 3, 2016	1-31447	4.1

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Exhibit Number	Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference
4.3	$300,000,000 Credit Agreement, dated as of March 3, 2016, among Houston Electric, as Borrower, and the banks named therein	CenterPoint Energy’s Form 8-K dated March 3, 2016	1-31447	4.2
4.4	$600,000,000 Credit Agreement, dated as of March 3, 2016, among CERC Corp., as Borrower, and the banks named therein	CenterPoint Energy’s Form 8-K dated March 3, 2016	1-31447	4.3
4.5	First Amendment to Amended and Restated Credit Agreement, dated as of June 16, 2017, by and among CenterPoint Energy, as Borrower, and the banks named therein	CenterPoint Energy’s Form 8-K dated June 16, 2017	1-31447	4.1
4.6	First Amendment to Credit Agreement, dated as of June 16, 2017, among Houston Electric, as Borrower, and the banks named therein	CenterPoint Energy’s Form 8-K dated June 16, 2017	1-31447	4.2
4.7	First Amendment to Credit Agreement, dated as of June 16, 2017, among CERC Corp., as Borrower, and the banks named therein	CenterPoint Energy’s Form 8-K dated June 16, 2017	1-31447	4.3
4.8	Indenture, dated as of May 19, 2003, between CenterPoint Energy and JPMorgan Chase Bank, as Trustee	CenterPoint Energy’s Form 8-K dated May 19, 2003	1-31447	4.1
+4.9	Supplemental Indenture No. 9 to Exhibit 4.8, dated as of August 10, 2017, providing for the issuance of CenterPoint Energy’s 2.50% Senior Notes due 2022
4.10	Indenture, dated as of February 1, 1998, between Reliant Energy Resources Corp. and Chase Bank of Texas, National Association, as Trustee	CERC Corp.’s Form 8-K dated February 5, 1998	1-13265	4.1
+4.11	Supplemental Indenture No. 16 to Exhibit 4.10, dated as of August 23, 2017, providing for the issuance of CERC Corp.’s 4.10% Senior Notes due 2047
+12	Computation of Ratios of Earnings to Fixed Charges
+31.1	Rule 13a-14(a)/15d-14(a) Certification of Scott M. Prochazka
+31.2	Rule 13a-14(a)/15d-14(a) Certification of William D. Rogers
+32.1	Section 1350 Certification of Scott M. Prochazka
+32.2	Section 1350 Certification of William D. Rogers
+101.INS	XBRL Instance Document
+101.SCH	XBRL Taxonomy Extension Schema Document
+101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
+101.DEF	XBRL Taxonomy Extension Definition Linkbase Document
+101.LAB	XBRL Taxonomy Extension Labels Linkbase Document
+101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.



	CENTERPOINT ENERGY, INC.


By:	/s/ Kristie L. Colvin
	Kristie L. Colvin
	Senior Vice President and Chief Accounting Officer

Date: November 3, 2017

Estimate Fair Value

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(in millions)

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Customer relationships