Edgar Filing: CENTERPOINT ENERGY INC

Document

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 JUNE 30, 2016



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



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

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

As of July 29, 2016, CenterPoint Energy, Inc. had 430,681,744 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 JUNE 30, 2016

TABLE OF CONTENTS



PART I.	FINANCIAL INFORMATION

Item 1.	Financial Statements	1

	Condensed Statements of Consolidated Income
	Three and Six Months Ended June 30, 2016 and 2015 (unaudited)	1

	Condensed Statements of Consolidated Comprehensive Income
	Three and Six Months Ended June 30, 2016 and 2015 (unaudited)	2

	Condensed Consolidated Balance Sheets
	June 30, 2016 and December 31, 2015 (unaudited)	3

	Condensed Statements of Consolidated Cash Flows
	Six Months Ended June 30, 2016 and 2015 (unaudited)	5

	Notes to Unaudited Condensed Consolidated Financial Statements	6

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	26

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	42

Item 4.	Controls and Procedures	43

PART II.	OTHER INFORMATION

Item 1.	Legal Proceedings	43

Item 1A.	Risk Factors	43

Item 5.	Other Information	43

Item 6.	Exhibits	44



GLOSSARY

AOL		AOL Inc.
APSC		Arkansas Public Service Commission
ArcLight		ArcLight Capital Partners, LLC
ASU		Accounting Standards Update
Bcf		Billion cubic feet
BDA		Billing Determinant Adjustment
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
CECL		Current expected credit losses
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.
Charter		Charter Communications, Inc.
Charter Common		Charter common stock
Choice customers		Residential and small commercial customers who have the option to choose a natural gas supplier as governed by the local distribution company’s filed transportation tariffs
CIP		Conservation Improvement Program
Continuum		The retail energy services business of Continuum Retail Energy Services, LLC, including its wholly-owned subsidiary Lakeshore Energy Services, LLC and the natural gas wholesale assets of Continuum Energy Services, LLC
DCRF		Distribution Cost Recovery Factor
Dodd-Frank		Dodd-Frank Wall Street Reform and Consumer Protection Act
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
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
Moody’s		Moody’s Investors Service, Inc.
MPSC		Mississippi Public Service Commission
MPUC		Minnesota Public Utilities Commission
NAV		Net asset value
NECA		National Electrical Contractors Association
NGD		Natural gas distribution business



GLOSSARY (cont.)

NGLs		Natural gas liquids
NRG		NRG Energy, Inc.
OGE		OGE Energy Corp.
PBRC		Performance Based Rate Change
PHMSA		Pipeline and Hazardous Materials Safety Administration
Private Placement		An agreement with Enable to purchase an aggregate of 14,520,000 Series A Preferred Units
PRPs		Potentially responsible parties
Reliant Energy		Reliant Energy, Incorporated
REP		Retail electric provider
ROE		Return on equity
ROR		Return on revenue
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		Enable’s 10% Series A Fixed-to-Floating Non-Cumulative Redeemable Perpetual Preferred Units
S&P		Standard & Poor’s Ratings Services, a division of The McGraw-Hill Companies
TCOS		Transmission Cost of Service
TDU		Transmission and distribution utility
Texas Utility Commission		Public Utility Commission of Texas
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
TWC		Time Warner Cable Inc.
TWC Common		TWC common stock
TW Securities		Charter Common, Time Common and TW Common
Verizon		Verizon Communications, Inc.
VIE		Variable interest entity
ZENS		2.0% Zero-Premium Exchangeable Subordinated Notes due 2029
2015 Form 10-K		Annual Report on Form 10-K for the year ended December 31, 2015

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,” “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;


•	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, health care reform, financial reform, tax legislation and actions regarding the rates charged by our regulated businesses;


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


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


•	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;


•	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;


•	effectiveness of our risk management activities;


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


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


•	acquisition and merger activities involving us or our competitors;


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


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


•	the outcome of litigation;


•	the ability of REPs, including REP affiliates of NRG and Energy Future Holdings 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 2015 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.

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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						Six Months Ended
	June 30,						June 30,
	2016			2015			2016			2015

Revenues	$	1,574		$	1,532		$	3,558		$	3,965

Expenses:
Natural gas	496			529			1,348			1,883
Operation and maintenance	513			488			1,034			986
Depreciation and amortization	289			239			549			456
Taxes other than income taxes	94			90			195			198
Total	1,392			1,346			3,126			3,523
Operating Income	182			186			432			442

Other Income (Expense):
Gain on marketable securities	20			79			110			62
Loss on indexed debt securities	(130		)	(91		)	(186		)	(67		)
Interest and other finance charges	(86		)	(89		)	(173		)	(178		)
Interest on securitization bonds	(23		)	(27		)	(47		)	(55		)
Equity in earnings of unconsolidated affiliate, net	31			43			91			95
Other, net	14			13			21			24
Total	(174		)	(72		)	(184		)	(119		)

Income Before Income Taxes	8			114			248			323
Income tax expense	10			37			96			115
Net Income (Loss)	$	(2	)	$	77		$	152		$	208

Basic Earnings (Loss) Per Share	$	(0.01	)	$	0.18		$	0.35		$	0.48

Diluted Earnings (Loss) Per Share	$	(0.01	)	$	0.18		$	0.35		$	0.48

Dividends Declared Per Share	$	0.2575		$	0.2475		$	0.5150		$	0.4950

Weighted Average Shares Outstanding, Basic	431			430			431			430

Weighted Average Shares Outstanding, Diluted	431			432			433			432

See Notes to Interim Condensed Consolidated Financial Statements

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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

CONDENSED STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME

(In Millions)

(Unaudited)



	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2016			2015		2016			2015
Net income (loss)	$	(2	)	$	77	$	152		$	208
Other comprehensive income (loss):
Adjustment related to pension and other postretirement plans (net of tax of $2, $-0-, $1 and $2)	(1		)	2		—			4
Net deferred loss from cash flow hedges (net of tax of $1, $-0-, $1, $-0-)	(1		)	—		(1		)	—
Total	(2		)	2		(1		)	4
Comprehensive income (loss)	$	(4	)	$	79	$	151		$	212

See Notes to Interim Condensed Consolidated Financial Statements

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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(In Millions)

(Unaudited)

ASSETS



	June 30, 2016		December 31, 2015
Current Assets:
Cash and cash equivalents ($246 and $264 related to VIEs, respectively)	$	271	$	264
Investment in marketable securities	737		805
Accounts receivable ($92 and $64 related to VIEs, respectively), less bad debt reserve of $24 and $20, respectively	605		593
Accrued unbilled revenues	178		279
Natural gas inventory	96		168
Materials and supplies	187		179
Non-trading derivative assets	47		89
Taxes receivable	16		172
Prepaid expenses and other current assets ($37 and $35 related to VIEs, respectively)	135		140
Total current assets	2,272		2,689

Property, Plant and Equipment:
Property, plant and equipment	17,218		16,650
Less: accumulated depreciation and amortization	5,320		5,113
Property, plant and equipment, net	11,898		11,537

Other Assets:
Goodwill	861		840
Regulatory assets ($2,156 and $2,373 related to VIEs, respectively)	2,913		3,129
Notes receivable – unconsolidated affiliate	—		363
Non-trading derivative assets	22		36
Investment in unconsolidated affiliate	2,536		2,594
Preferred units – unconsolidated affiliate	363		—
Other	147		102
Total other assets	6,842		7,064

Total Assets	$	21,012	$	21,290

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



	June 30, 2016			December 31, 2015
Current Liabilities:
Short-term borrowings	$	17		$	40
Current portion of VIE securitization bonds long-term debt	402			391
Indexed debt	111			145
Current portion of other long-term debt	250			328
Indexed debt securities derivative	490			442
Accounts payable	407			483
Taxes accrued	92			158
Interest accrued	119			117
Non-trading derivative liabilities	19			11
Other	334			343
Total current liabilities	2,241			2,458

Other Liabilities:
Deferred income taxes, net	5,121			5,047
Non-trading derivative liabilities	6			5
Benefit obligations	904			904
Regulatory liabilities	1,284			1,276
Other	279			273
Total other liabilities	7,594			7,505

Long-term Debt:
VIE securitization bonds	2,059			2,276
Other long-term debt	5,721			5,590
Total long-term debt	7,780			7,866

Commitments and Contingencies (Note 14)

Shareholders’ Equity:
Common stock (430,681,491 shares and 430,262,703 shares outstanding, respectively)	4			4
Additional paid-in capital	4,186			4,180
Accumulated deficit	(726		)	(657		)
Accumulated other comprehensive loss	(67		)	(66		)
Total shareholders’ equity	3,397			3,461

Total Liabilities and Shareholders’ Equity	$	21,012		$	21,290

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)



	Six Months Ended June 30,
	2016			2015
Cash Flows from Operating Activities:
Net income	$	152		$	208
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	549			456
Amortization of deferred financing costs	13			14
Deferred income taxes	69			4
Unrealized gain on marketable securities	(110		)	(62		)
Loss on indexed debt securities	186			67
Write-down of natural gas inventory	1			2
Equity in (earnings) losses of unconsolidated affiliate, net of distributions	(91		)	50
Pension contributions	(5		)	(25		)
Changes in other assets and liabilities, excluding acquisitions:
Accounts receivable and unbilled revenues, net	147			367
Inventory	63			103
Taxes receivable	156			152
Accounts payable	(109		)	(327		)
Fuel cost recovery	(17		)	86
Non-trading derivatives, net	22			2
Margin deposits, net	65			25
Interest and taxes accrued	(64		)	(66		)
Net regulatory assets and liabilities	(21		)	78
Other current assets	4			23
Other current liabilities	21			(38		)
Other liabilities	17			(3		)
Other, net	10			6
Net cash provided by operating activities	1,058			1,122
Cash Flows from Investing Activities:
Capital expenditures	(682		)	(712		)
Acquisitions, net of cash acquired	(98		)	—
Decrease in notes receivable – unconsolidated affiliate	363			—
Investment in preferred units – unconsolidated affiliate	(363		)	—
Distributions from unconsolidated affiliate in excess of cumulative earnings	149			—
Decrease (increase) in restricted cash of Bond Companies	(2		)	13
Proceeds from sale of marketable securities	178			32
Other, net	(12		)	(4		)
Net cash used in investing activities	(467		)	(671		)
Cash Flows from Financing Activities:
Decrease in short-term borrowings, net	(23		)	(29		)
Proceeds of commercial paper, net	278			137
Proceeds from long-term debt	300			—
Payments of long-term debt	(735		)	(400		)
Debt issuance costs	(7		)	—
Payment of common stock dividends	(221		)	(213		)
Distribution to ZENS note holders	(178		)	—
Other, net	2			1
Net cash used in financing activities	(584		)	(504		)
Net Increase (Decrease) in Cash and Cash Equivalents	7			(53		)
Cash and Cash Equivalents at Beginning of Period	264			298
Cash and Cash Equivalents at End of Period	$	271		$	245
Supplemental Disclosure of Cash Flow Information:
Cash Payments:
Interest, net of capitalized interest	$	200		$	209
Income tax refunds, net	(126		)	(38		)
Non-cash transactions:
Accounts payable related to capital expenditures	79			81

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 2015 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 facilities and natural gas distribution facilities, and both CenterPoint Energy and its operating subsidiaries own interests in Enable as described in Note 8. As of June 30, 2016, CenterPoint Energy’s indirect, wholly-owned subsidiaries included:


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

•

CERC Corp. (together with its subsidiaries), which owns and operates natural gas distribution systems. A wholly-owned subsidiary of CERC Corp. offers variable and fixed-price physical natural gas supplies primarily to commercial and industrial customers and electric and natural gas utilities. As of June 30, 2016, CERC Corp. also owned approximately 55.4% of the limited partner interests in Enable, which owns, operates and develops natural gas and crude oil infrastructure assets.

As of June 30, 2016, CenterPoint Energy had VIEs consisting of 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 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 16.

(2) New Accounting Pronouncements

In February 2015, the FASB issued ASU No. 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis (ASU 2015-02). ASU 2015-02 changes the analysis that reporting organizations must perform to evaluate whether they should consolidate certain legal entities, such as limited partnerships. The changes include, among others, modification of the evaluation of whether limited partnerships and similar legal entities are VIEs or voting interest entities and elimination of the presumption that a general partner should consolidate a limited partnership. ASU 2015-02 does not amend the related party guidance for situations in which power is shared between two or more entities that hold interests in a VIE. CenterPoint Energy adopted ASU 2015-02 on January 1, 2016, which CenterPoint Energy determined did not have a material impact on its financial position, results of operations, cash flows and disclosures.

In April 2015, the FASB issued ASU No. 2015-03, Interest-Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Cost (ASU 2015-03). ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by ASU 2015-03. CenterPoint Energy adopted ASU 2015-03 retrospectively on January 1, 2016, which resulted in a reduction of other long-term assets, indexed debt

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and total long-term debt on its Condensed Consolidated Balance Sheets. CenterPoint Energy had debt issuance costs, excluding amounts related to credit facility arrangements, of $43 million and $44 million as of June 30, 2016 and December 31, 2015, respectively.

In May 2015, the FASB issued ASU No. 2015-07, Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent) (ASU 2015-07). ASU 2015-07 removes the requirement to categorize within the fair value hierarchy investments for which fair values are measured at NAV using the practical expedient. Entities will be required to disclose the fair value of investments measured using the NAV practical expedient so that financial statement users can reconcile amounts reported in the fair value hierarchy table to amounts reported on the balance sheet. CenterPoint Energy adopted ASU 2015-07 on January 1, 2016, which will have an impact on its employee benefit plan disclosures, beginning with its annual report on Form 10-K for the year ended December 31, 2016. This standard did not have an impact on CenterPoint Energy’s financial position, results of operations or cash flows.

In September 2015, the FASB issued ASU No. 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments (ASU 2015-16). ASU 2015-16 eliminates the requirement for an acquirer in a business combination to account for measurement-period adjustments retrospectively. Instead, an acquirer would recognize a measurement-period adjustment during the period in which the amount of the adjustment is determined. CenterPoint Energy adopted ASU 2015-16 on January 1, 2016, which did not have an impact on its financial position, results of operations or cash flows.

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. CenterPoint Energy is currently assessing the impact that this standard will have on its financial position, results of operations, cash flows and disclosures.

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). 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. 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. 2016-05, Derivatives and Hedging (Topic 815): Effect of Derivative Contract Novation on Existing Hedge Accounting Relationships (ASU 2016-05). ASU 2016-05 clarifies that a change in the counterparty to a derivative instrument that has been designated as the hedging instrument in an existing hedging relationship would not, in and of itself, be considered a termination of the derivative instrument or a change in a critical term of the hedging relationship. This clarification applies to both cash flow and fair value hedging relationships. CenterPoint Energy adopted ASU 2016-05 prospectively in the first quarter of 2016, which did not have an impact on its financial position, results of operations, cash flows and disclosures.

In March, April, and May 2016, the FASB issued ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (ASU 2016-08), ASU No. 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing (ASU 2016-10), and ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients (ASU 2016-12), respectively. ASU 2016-08, ASU 2016-10, and ASU 2016-12 clarify certain aspects of ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) (ASU 2014-09), which supersedes most current revenue recognition guidance. CenterPoint Energy is currently evaluating the impact that ASU 2016-08, ASU 2016-10, ASU 2016-12, and ASU 2014-09 will have on its financial position, results of operations, cash flows and disclosures and expects to adopt these ASUs on January 1, 2018.

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). ASU 2016-09 will change the accounting for certain aspects of share-based payments to employees, including the recognition of income tax effects of vested or settled awards in the income statement, instead of within additional paid-in capital. It will also increase the amount an employer can withhold to cover income taxes on awards and still qualify for the exception to liability classification for shares used to satisfy the employer’s statutory income tax withholding obligations. ASU 2016-09 will allow companies to elect between two different methods to account for forfeitures of share-based payments. ASU 2016-09 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016, with early adoption permitted. CenterPoint Energy is currently assessing the impact that this standard will have on its financial position, results of operations, cash flows and disclosures.

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In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments (ASU 2016-13). ASU 2016-13 requires a new model called the CECL model to estimate credit losses for financial assets subject to credit losses and measured at amortized cost and certain off-balance sheet credit exposures. This includes loans, held-to-maturity debt securities, loan commitments, financial guarantees, and net investments in leases, as well as reinsurance and trade receivables. Upon initial recognition of the exposure, the CECL model requires an entity to estimate the credit losses expected over the life of an exposure based on historical information, current information and reasonable and supportable forecasts, including estimates of prepayments. The update also amends the other-than-temporary impairment model for debt securities classified as available-for-sale. ASU 2016-13 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019, with early adoption permitted beginning after December 15, 2018. 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 April 1, 2016, CES, an indirect, wholly-owned subsidiary of CenterPoint Energy, closed the previously announced agreement to acquire the retail energy services business and natural gas wholesale assets of Continuum for $98 million. The purchase price was allocated to identifiable assets acquired and liabilities assumed based on their estimated fair values on the acquisition date. As additional information becomes available, the preliminary purchase price allocation may be revised during the remainder of the measurement period (which will not exceed 12 months from the acquisition date). Any such revisions or changes are not expected to be material.

The following table summarizes the total preliminary 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	$	98
Receivables	$	75
Derivative assets	38
Property and equipment	1
Identifiable intangibles	36
Total assets acquired	150
Accounts payable	49
Derivative liabilities	24
Total liabilities assumed	73
Identifiable net assets acquired	77
Goodwill	21
Net assets acquired	$	98

The goodwill of $21 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 provided, along with the scale, geographic reach and expanded capabilities.

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.

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



	Estimate Fair Value		Estimate Useful Life
	(in millions)		(in years)
Customer relationships	$	32	15
Covenants not to compete	4		4
Total identifiable intangibles	$	36

Amortization expense related to the above identifiable intangible assets was $1 million for the three and six months ended June 30, 2016 and is expected to be $2 million for 2016.

Revenues of $108 million and operating income of less than $1 million attributable to the acquisition are included in CenterPoint Energy’s Condensed Consolidated Statements of Income for the three and six months ended June 30, 2016.

As Continuum was a non-public company that did not prepare interim financial information, the historical financial information for the businesses and assets acquired was impracticable to obtain. As a result, pro forma results of the acquired businesses and assets are not presented.

(4) Employee Benefit Plans

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



	Three Months Ended June 30,
	2016						2015
	Pension Benefits (1)			Postretirement Benefits (1)			Pension Benefits (1)			Postretirement Benefits (1)
	(in millions)
Service cost	$	9		$	—		$	10		$	—
Interest cost	24			5			23			5
Expected return on plan assets	(25		)	(1		)	(30		)	(1		)
Amortization of prior service cost (credit)	2			(1		)	2			(1		)
Amortization of net loss	16			—			15			1
Curtailment gain (3)	—			(3		)	—			—
Net periodic cost	$	26		$	—		$	20		$	4

	Six Months Ended June 30,
	2016						2015
	Pension Benefits (1)			Postretirement Benefits (1)			Pension Benefits (1)			Postretirement Benefits (1)
	(in millions)
Service cost	$	18		$	1		$	20		$	1
Interest cost	47			9			46			10
Expected return on plan assets	(50		)	(3		)	(60		)	(3		)
Amortization of prior service cost (credit)	4			(1		)	5			(1		)
Amortization of net loss	32			—			29			2
Settlement cost (2)	—			—			9			—
Curtailment gain (3)	—			(3		)	—			—
Net periodic cost	$	51		$	3		$	49		$	9


(1)	Net periodic cost in these tables is before considering amounts subject to overhead allocations for capital expenditure projects or for amounts subject to deferral for regulatory purposes.


(2)	A one-time, non-cash settlement charge is required when lump sum distributions or other settlements of plan benefit obligations during a plan year exceed the service cost and interest cost components of net periodic cost for that year. Due to the amount of lump sum payment distributions from the non-qualified pension plan during the six months ended

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June 30, 2015, CenterPoint Energy recognized a non-cash settlement charge of $9 million. This charge is an acceleration of costs that would otherwise be recognized in future periods.

(3)

A curtailment gain or loss is required when the expected future services of a significant number of current employees are reduced or eliminated for the accrual of benefits. 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. 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.

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
	Pension and Postretirement Plans						Pension and Postretirement Plans
	(in millions)
Beginning Balance	$	(64	)	$	(83	)	$	(65	)	$	(85	)
Other comprehensive income (loss) before reclassifications (1)	(4		)	—			(4		)	—
Amounts reclassified from accumulated other comprehensive loss:
Actuarial losses (2)	1			2			3			6
Tax benefit (expense)	2			—			1			(2		)
Net current period other comprehensive income (loss)	(1		)	2			—			4
Ending Balance	$	(65	)	$	(81	)	$	(65	)	$	(81	)


(1)	Total other comprehensive income (loss) 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 total of approximately $8 million to its pension plans in 2016, of which approximately $2 million and $5 million were contributed during the three and six months ended June 30, 2016, respectively.

CenterPoint Energy expects to contribute a total of approximately $16 million to its postretirement benefit plan in 2016, of which approximately $4 million and $8 million were contributed during the three and six months ended June 30, 2016, respectively.

(5) Regulatory Accounting

As of June 30, 2016, Houston Electric has not recognized an allowed equity return of $363 million because such return will be recognized as it is recovered in rates. During the three months ended June 30, 2016 and 2015, Houston Electric recognized approximately $17 million and $12 million, respectively, of the allowed equity return not previously recognized. During the six months ended June 30, 2016 and 2015, Houston Electric recognized approximately $30 million and $21 million, respectively, of the allowed equity return not previously recognized.

(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 and weather 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.

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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 manage physical commodity price risk and does not engage in proprietary or speculative commodity trading. These 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 has historically entered into heating-degree day swaps for certain NGD jurisdictions to mitigate the effect of fluctuations from normal weather on its results of operations and cash flows for the winter heating season, which contained a bilateral dollar cap of $16 million in 2014–2015. However, NGD did not enter into heating-degree day swaps for the 2015–2016 winter season as a result of NGD’s Minnesota division implementing a full decoupling pilot in July 2015. CenterPoint Energy also entered into weather hedges for the Houston Electric service territory, which contained a bilateral dollar cap of $8 million for the 2014–2015 winter season and a bilateral dollar cap of $7 million for the 2015–2016 winter season. The swaps are based on 10-year normal weather. During the three months ended June 30, 2016 and 2015, CenterPoint Energy recognized gains of $-0- and $1 million, respectively, related to these swaps. During the six months ended June 30, 2016 and 2015, CenterPoint Energy recognized gains of $3 million and losses of $9 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 April 2016, 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 5-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 May 2016. These forward interest rate agreements were designated as cash flow hedges. Accordingly, the ineffective portion of unrealized gains and losses associated with the agreements was recorded in income and was immaterial.

In June and July 2016, Houston Electric entered into forward interest rate agreements with several counterparties, having an aggregate notional amount of $300 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 relating to interest payments on a forecasted issuance of fixed rate debt in 2016. These forward interest rate agreements were designated as cash flow hedges. As of June 30, 2016, a $2 million current non-trading derivative liability was recorded on the Condensed Consolidated Balance Sheets related to these agreements. Accordingly, the effective portion of unrealized gains and losses associated with the agreements would be recorded as a component of accumulated other comprehensive income and the ineffective portion would be recorded in income.

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(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 June 30, 2016 and December 31, 2015, while the last table provides a breakdown of the related income statement impacts for the three and six months ended June 30, 2016 and 2015.



Fair Value of Derivative Instruments
	June 30, 2016
Total derivatives not designated as hedging instruments	Balance Sheet Location	Derivative Assets Fair Value		Derivative Liabilities Fair Value
		(in millions)
Natural gas derivatives (1) (2) (3)	Current Assets: Non-trading derivative assets	$	49	$	2
Natural gas derivatives (1) (2) (3)	Other Assets: Non-trading derivative assets	28		6
Natural gas derivatives (1) (2) (3)	Current Liabilities: Non-trading derivative liabilities	28		45
Natural gas derivatives (1) (2) (3)	Other Liabilities: Non-trading derivative liabilities	—		6
Indexed debt securities derivative	Current Liabilities	—		490
Total		$	105	$	549


(1)	The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling 1,085 Bcf or a net 6 Bcf short position. Of the net short position, basis swaps constitute a net 136 Bcf long position.

(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 $46 million asset, excluding a $2 million interest rate derivative liability, 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, offset by collateral netting of less than $1 million.


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



Offsetting of Natural Gas Derivative Assets and Liabilities
	June 30, 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	$	77		$	(30	)	$	47
Other Assets: Non-trading derivative assets	28			(6		)	22
Current Liabilities: Non-trading derivative liabilities	(47		)	30			(17		)
Other Liabilities: Non-trading derivative liabilities	(12		)	6			(6		)
Total	$	46		$	—		$	46


(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.

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Fair Value of Derivative Instruments
	December 31, 2015
Total derivatives not designated as hedging instruments	Balance Sheet Location	Derivative Assets Fair Value		Derivative Liabilities Fair Value
		(in millions)
Natural gas derivatives (1) (2) (3)	Current Assets: Non-trading derivative assets	$	90	$	2
Natural gas derivatives (1) (2) (3)	Other Assets: Non-trading derivative assets	36		—
Natural gas derivatives (1) (2) (3)	Current Liabilities: Non-trading derivative liabilities	10		60
Natural gas derivatives (1) (2) (3)	Other Liabilities: Non-trading derivative liabilities	4		25
Indexed debt securities derivative	Current Liabilities	—		442
Total		$	140	$	529


(1)	The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling 767 Bcf or a net 112 Bcf long position. Of the net long position, basis swaps constitute 133 Bcf.

(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 $109 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, offset by collateral netting of $56 million.


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



Offsetting of Natural Gas Derivative Assets and Liabilities
	December 31, 2015
	Gross Amounts Recognized (1)			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amount Presented in the Consolidated Balance Sheets (2)
	(in millions)
Current Assets: Non-trading derivative assets	$	100		$	(11	)	$	89
Other Assets: Non-trading derivative assets	40			(4		)	36
Current Liabilities: Non-trading derivative liabilities	(62		)	51			(11		)
Other Liabilities: Non-trading derivative liabilities	(25		)	20			(5		)
Total	$	53		$	56		$	109


(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.

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




Income Statement Impact of Derivative Activity
		Three Months Ended June 30,
Total derivatives not designated as hedging instruments	Income Statement Location	2016			2015
		(in millions)
Natural gas derivatives	Gains (Losses) in Revenues	$	(50	)	$	7
Natural gas derivatives	Gains (Losses) in Expenses: Natural Gas	59			1
Indexed debt securities derivative	Gains (Losses) in Other Income (Expense)	(130		)	(91		)
Total		$	(121	)	$	(83	)



Income Statement Impact of Derivative Activity
		Six Months Ended June 30,
Total derivatives not designated as hedging instruments	Income Statement Location	2016			2015
		(in millions)
Natural gas derivatives	Gains (Losses) in Revenues	$	(30	)	$	49
Natural gas derivatives	Gains (Losses) in Expenses: Natural Gas	48			(42		)
Indexed debt securities derivative	Gains (Losses) in Other Income (Expense)	(186		)	(67		)
Total		$	(168	)	$	(60	)


(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 June 30, 2016 and December 31, 2015 was $3 million. CenterPoint Energy posted no assets as collateral towards derivative instruments that contain credit risk contingent features as of either June 30, 2016 or December 31, 2015. If all derivative contracts (in a net liability position) containing credit risk contingent features were triggered as of both June 30, 2016 and December 31, 2015, $2 million 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.

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 June 30, 2016, CenterPoint Energy’s Level 3 assets and liabilities are comprised of physical forward contracts and options. Level 3 physical forward contracts are valued using a discounted cash flow model which includes illiquid forward price curve locations (ranging from $1.92 to $3.72 per one million British thermal units) as an unobservable input. Level 3 options are valued through Black-Scholes (including forward start) option models which

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include option volatilities (ranging from 0% to 85%) as an unobservable input. CenterPoint Energy’s Level 3 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 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 six months ended June 30, 2016, there were no transfers between Level 1 and 2. CenterPoint Energy also recognizes purchases of Level 3 financial assets and liabilities at their fair market value at the end of the reporting period.

The following tables present information about CenterPoint Energy’s assets and liabilities (including derivatives that are presented net) measured at fair value on a recurring basis as of June 30, 2016 and December 31, 2015, and indicate the fair value hierarchy of the valuation techniques utilized by CenterPoint Energy to determine such fair value.



	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Netting Adjustments (1)			Balance as of June 30, 2016
			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Netting Adjustments (1)			Balance as of June 30, 2016
	(in millions)
Assets
Corporate equities	$	739	$	—	$	—	$	—		$	739
Investments, including money market funds (2)	55		—		—		—			55
Natural gas derivatives (3)	7		77		21		(36		)	69
Total assets	$	801	$	77	$	21	$	(36	)	$	863
Liabilities
Indexed debt securities derivative	$	—	$	490	$	—	$	—		$	490
Interest rate derivatives	—		2		—		—			2
Natural gas derivatives (3)	5		49		5		(36		)	23
Total liabilities	$	5	$	541	$	5	$	(36	)	$	515


(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 less than $1 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.



	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Netting Adjustments (1)			Balance as of December 31, 2015
			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Netting Adjustments (1)			Balance as of December 31, 2015
	(in millions)
Assets
Corporate equities	$	807	$	—	$	—	$	—		$	807
Investments, including money market funds (2)	53		—		—		—			53
Natural gas derivatives (3)	4		115		21		(15		)	125
Total assets	$	864	$	115	$	21	$	(15	)	$	985
Liabilities
Indexed debt securities derivative	$	—	$	442	$	—	$	—		$	442
Natural gas derivatives (3)	13		65		9		(71		)	16
Total liabilities	$	13	$	507	$	9	$	(71	)	$	458


(1)	Amounts represent the impact of legally enforceable master netting arrangements that allow CenterPoint Energy to settle positive and negative positions and also include cash collateral of $56 million posted with the same counterparties.

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(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.

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 June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
	(in millions)
Beginning balance	$	15		$	13		$	12		$	17
Purchases	12			—			12			—
Total gains	—			—			4			—
Total settlements	(11		)	(3		)	(16		)	(6		)
Transfers into Level 3	—			—			5			—
Transfers out of Level 3	—			—			(1		)	(1		)
Ending balance (1)	$	16		$	10		$	16		$	10
The amount of total gains for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the reporting date	$	3		$	—		$	11		$	2


(1)	CenterPoint Energy did not have significant Level 3 sales during either of the three or six months ended June 30, 2016 or 2015.

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 the market price. These assets and 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 1 or Level 2 in the fair value hierarchy.



	June 30, 2016				December 31, 2015
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)
Financial assets:
Notes receivable – unconsolidated affiliate	$	—	$	—	$	363	$	356
Financial liabilities:
Long-term debt	$	8,432	$	9,207	$	8,585	$	9,067

(8) Unconsolidated Affiliate

On May 1, 2013 (the Formation Date) CERC Corp., OGE and ArcLight closed on the formation of Enable. CenterPoint Energy has the ability to significantly influence the operating and financial policies of Enable and, accordingly, accounts for its investment in Enable’s common and subordinated 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 preferred unit investment as presented in the Condensed Consolidated Balance Sheets as of June 30, 2016, the guarantees discussed in Note 14, and outstanding current accounts receivable from Enable. On February 18, 2016, CenterPoint Energy purchased in a Private Placement an aggregate of 14,520,000 Series A Preferred Units

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from Enable for a total purchase price of $363 million, which is accounted for as a cost method investment. During the three months ended June 30, 2016, CenterPoint Energy received a cash distribution of approximately $4 million for the partial period from February 18, 2016 through March 31, 2016 with respect to its investment in Series A Preferred Units. In connection with the Private Placement, Enable redeemed $363 million of notes owed to a wholly-owned subsidiary of CERC Corp., which bore interest at an annual rate of 2.10% to 2.45%. CenterPoint Energy recorded interest income of $-0- and $2 million during the three months ended June 30, 2016 and 2015, respectively, and $1 million and $4 million during the six months ended June 30, 2016 and 2015, respectively, and had interest receivable from Enable of $-0- and $4 million as of June 30, 2016 and December 31, 2015, respectively, on its notes receivable.

Effective on the Formation Date, CenterPoint Energy and Enable entered into the Transition Agreements. Under the Services Agreement, CenterPoint Energy agreed to provide certain support services to Enable such as accounting, legal, risk management and treasury functions for an initial term, which ended on April 30, 2016. CenterPoint Energy is providing certain services to Enable on a year-to-year basis. Enable may terminate (i) the entire Services Agreement with at least 90 days’ notice prior to the end of any extension term, or (ii) either any service provided under the Services Agreement, or the entire Services Agreement, at any time upon approval by its board of directors and with at least 180 days’ notice.

CenterPoint Energy billed Enable for reimbursement of transition services of $2 million during both the three months ended June 30, 2016 and 2015, and $5 million and $7 million during the six months ended June 30, 2016 and 2015, respectively, under the Transition Agreements. Actual transition services costs are recorded net of reimbursements received from Enable. CenterPoint Energy had accounts receivable from Enable of $1 million and $3 million as of June 30, 2016 and December 31, 2015, respectively, for amounts billed for transition services.

CenterPoint Energy incurred natural gas expenses, including transportation and storage costs, of $24 million and $26 million during the three months ended June 30, 2016 and 2015, respectively, and $57 million and $65 million during the six months ended June 30, 2016 and 2015, respectively, for transactions with Enable. CenterPoint Energy had accounts payable to Enable of $8 million and $11 million as of June 30, 2016 and December 31, 2015, respectively, from such transactions.

As of June 30, 2016, CenterPoint Energy held an approximate 55.4% limited partner interest in Enable, consisting of 94,151,707 common units and 139,704,916 subordinated units. As of June 30, 2016, CenterPoint Energy and OGE each own a 50% management interest in the general partner of Enable and a 40% and 60% interest, respectively, in the incentive distribution rights held by the general partner. Additionally, as of June 30, 2016, CenterPoint Energy held 14,520,000 Series A Preferred Units in Enable.

CenterPoint Energy evaluates its equity method investments and cost method investments for impairment when factors indicate that a decrease in value of its investment has occurred and the carrying amount of its investment may not be recoverable. An impairment loss, based on the excess of the carrying value over the best estimate of fair value of the investment, is recognized in earnings when an impairment is deemed to be other than temporary. Considerable judgment is used in determining if an impairment loss is other than temporary and the amount of any impairment. As of June 30, 2016, the carrying value of CenterPoint Energy’s equity method investment in Enable was $10.85 per unit, which includes limited partner common and subordinated units, a general partner interest and incentive distribution rights. On June 30, 2016, Enable’s common unit price closed at $13.51.

As there were no identified events or changes in circumstances that may have a significant adverse effect on the fair value of CenterPoint Energy’s cost method investment in Enable’s Series A Preferred Units as of June 30, 2016, and the investment’s fair value is not readily determinable, an estimate of the fair value of the cost method investment was not performed.

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Summarized unaudited consolidated income information for Enable is as follows:



	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
	(in millions)
Operating revenues	$	529	$	590	$	1,038	$	1,206
Cost of sales, excluding depreciation and amortization	254		277		449		569
Operating income	57		93		160		197
Net income attributable to Enable	35		77		121		168

Reconciliation of Equity in Earnings, net:
CenterPoint Energy’s interest	$	19	$	42	$	67	$	93
Basis difference amortization	12		1		24		2
CenterPoint Energy’s equity in earnings, net	$	31	$	43	$	91	$	95

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



	June 30, 2016			December 31, 2015
	(in millions)
Current assets	$	349		$	381
Non-current assets	10,851			10,857
Current liabilities	301			615
Non-current liabilities	3,150			3,092
Non-controlling interest	11			12
Preferred equity	362			—
Enable partners’ equity	7,376			7,519

Reconciliation of Equity Method Investment in Enable:
CenterPoint Energy’s ownership interest in Enable partners’ capital	$	4,084		$	4,163
CenterPoint Energy’s basis difference	(1,548		)	(1,569		)
CenterPoint Energy’s equity method investment in Enable	$	2,536		$	2,594

Distributions Received from Unconsolidated Affiliate:



	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
	(in millions)
Enable	$	75	$	73	$	149	$	145

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(9) Goodwill

Goodwill by reportable business segment as of December 31, 2015 and changes in the carrying amount of goodwill as of June 30, 2016 are as follows:



	December 31, 2015			Continuum Acquisition (1)		June 30, 2016
	(in millions)
Natural Gas Distribution	$	746		$	—	$	746
Energy Services	83		(2)	21		104
Other Operations	11			—		11
Total	$	840		$	21	$	861

(1) See Note 3.

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

(10) Capital Stock

CenterPoint Energy, Inc. has 1,020,000,000 authorized shares of capital stock, comprised of 1,000,000,000 shares of $0.01 par value common stock and 20,000,000 shares of $0.01 par value cumulative preferred stock. As of June 30, 2016, 430,681,657 shares of CenterPoint Energy, Inc. common stock were issued and 430,681,491 shares were outstanding. As of December 31, 2015, 430,262,869 shares of CenterPoint Energy, Inc. common stock were issued and 430,262,703 shares were outstanding. Outstanding common shares exclude 166 treasury shares as of both June 30, 2016 and December 31, 2015.

(11) 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 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 at June 30, 2016. Each ZENS note was originally exchangeable at the holder’s option at any time for an amount of cash equal to 95% of the market value of the reference shares of TW Common attributable to such note. The number and identity of the reference shares attributable to each ZENS note are adjusted for certain corporate events. Prior to the merger described below, the reference shares for each ZENS note consisted of 0.5 share of TW Common, 0.125505 share of TWC Common and 0.0625 share of Time Common.

On May 26, 2015, Charter announced that it had entered into a definitive merger agreement with TWC. On September 21, 2015, Charter shareholders approved the announced transaction with TWC. Pursuant to the merger agreement, upon closing of the merger, TWC Common would be exchanged for cash and Charter Common and as a result, reference shares for the ZENS would consist of Charter Common, TW Common and Time Common. The merger closed on May 18, 2016. CenterPoint Energy received $100 and 0.4891 shares of Charter Common for each share of TWC Common held, resulting in cash proceeds of $178 million and 872,531 shares of Charter Common. In accordance with the terms of the ZENS, CenterPoint Energy remitted $178 million to ZENS note holders in June 2016, which reduced contingent principal. As a result, CenterPoint Energy recorded the following:



	(in millions)
Cash payment to ZENS note holders	$	178
Indexed debt – reduction	(40		)
Indexed debt securities derivative – reduction	(21		)
Loss on indexed debt securities	$	117

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As of June 30, 2016, the reference shares for each ZENS note 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 $519 million.

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


(a)	Short-term Borrowings

Inventory Financing. NGD has asset management agreements associated with its utility distribution service in Arkansas, north Louisiana and Oklahoma that extend through 2019. Pursuant to the provisions of the agreements, NGD sells natural gas and agrees to repurchase an equivalent amount of natural gas during the winter heating seasons at the same cost, plus a financing charge. These transactions are accounted for as a financing and had an associated principal obligation of $17 million and $40 million as of June 30, 2016 and December 31, 2015, respectively.


(b)	Long-term Debt

Debt Repayments. In May 2016, CERC retired approximately $325 million aggregate principal amount of its 6.15% senior notes at their maturity. The retirement of senior notes was financed by the issuance of commercial paper.

Houston Electric General Mortgage Bonds. In May 2016, Houston Electric issued $300 million aggregate principal amount of 1.85% general mortgage bonds due 2021. The proceeds from the issuance of the bonds were used to repay short-term debt and for general corporate purposes.

Credit Facilities. On March 4, 2016, CenterPoint Energy announced that it had refinanced its existing $2.1 billion revolving credit facilities, which would have expired in 2019, with new revolving credit facilities totaling an aggregate $2.5 billion. The credit agreements evidencing the new revolving credit facilities provide for five-year senior unsecured revolving credit facilities in amounts of $1.6 billion for CenterPoint Energy, $300 million for Houston Electric and $600 million for CERC Corp.

As of June 30, 2016 and December 31, 2015, CenterPoint Energy, Houston Electric and CERC Corp. had the following revolving credit facilities and utilization of such facilities:



	June 30, 2016									December 31, 2015
	Size of Facility		Loans		Letters of Credit		Commercial Paper			Size of Facility		Loans			Letters of Credit		Commercial Paper
	(in millions)
CenterPoint Energy	$	1,600	$	—	$	6	$	1,037	(1)	$	1,200	$	—		$	6	$	716	(1)
Houston Electric	300		—		4		—			300		200		(2)	4		—
CERC Corp.	600		—		3		176		(3)	600		—			2		219		(3)
Total	$	2,500	$	—	$	13	$	1,213		$	2,100	$	200		$	12	$	935


(1)	Weighted average interest rate was 0.82% and 0.79% as of June 30, 2016 and December 31, 2015, respectively.


(2)	Weighted average interest rate was 1.637% as of December 31, 2015.


(3)	Weighted average interest rate was 0.68% and 0.81% as of June 30, 2016 and December 31, 2015, respectively.

CenterPoint Energy’s $1.6 billion revolving credit facility, which is scheduled to terminate on March 3, 2021, can be drawn at LIBOR plus 1.25% based on CenterPoint Energy’s current credit ratings. The revolving credit facility contains a financial covenant which limits CenterPoint Energy’s consolidated debt (with certain exceptions, including but not limited to Securitization Bonds) to an amount not to exceed 65% of CenterPoint Energy’s consolidated capitalization. As of June 30, 2016, CenterPoint Energy’s debt (excluding Securitization Bonds) to capital ratio, as defined in its credit facility agreement, was 55.5%. 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 twelve-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.

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Houston Electric’s $300 million revolving credit facility, which is scheduled to terminate on March 3, 2021, can be drawn at LIBOR plus 1.125% based on Houston Electric’s current credit ratings. The revolving credit facility contains a financial covenant which limits Houston Electric’s consolidated debt (with certain exceptions, including but not limited to Securitization Bonds) to an amount not to exceed 65% of Houston Electric’s consolidated capitalization. As of June 30, 2016, Houston Electric’s debt (excluding Securitization Bonds) to capital ratio, as defined in its credit facility agreement, was 52.7%. 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 Houston Electric certifies to the administrative agent that Houston Electric has incurred system restoration costs reasonably likely to exceed $100 million in a consecutive twelve-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 Houston Electric delivers its certification until the earliest to occur of (i) the completion of the securitization financing, (ii) the first anniversary of Houston Electric’s certification or (iii) the revocation of such certification.

CERC Corp.’s $600 million revolving credit facility, which is scheduled to terminate on March 3, 2021, can be drawn at LIBOR plus 1.25% based on CERC Corp.’s current credit ratings. The revolving credit facility contains a financial covenant which limits CERC’s consolidated debt to an amount not to exceed 65% of CERC’s consolidated capitalization. As of June 30, 2016, CERC’s debt to capital ratio, as defined in its credit facility agreement, was 30.7%.

CenterPoint Energy, Houston Electric and CERC Corp. were in compliance with all financial covenants as of June 30, 2016.

(13) Income Taxes

The effective tax rate reported for the three months ended June 30, 2016 was 125% compared to 32% for the same period in 2015. The higher effective tax rate for the three months ended June 30, 2016 is due to a Louisiana state tax law change resulting in an increase to CenterPoint Energy’s deferred tax liability, the effect of which was compounded by lower earnings.

The effective tax rate reported for the six months ended June 30, 2016 was 39% compared to 36% for the same period in 2015. The higher effective tax rate for the six months ended June 30, 2016 is due to a Louisiana state tax law change discussed above.

CenterPoint Energy reported no uncertain tax liability as of June 30, 2016 and expects no significant change to the uncertain tax liability over the next twelve months. CenterPoint Energy’s consolidated federal income tax returns have been audited and settled through 2014. CenterPoint Energy is under examination by the IRS for 2015 and 2016.

(14) 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 June 30, 2016 and December 31, 2015 as these contracts meet an exception as “normal purchases contracts” or do not meet the definition of a derivative. Natural gas supply commitments also include natural gas transportation contracts that do not meet the definition of a derivative. As of June 30, 2016, minimum payment obligations for natural gas supply commitments are approximately $190 million for the remaining six months in 2016, $473 million in 2017, $456 million in 2018, $270 million in 2019, $132 million in 2020 and $127 million after 2020.


(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, nor does it affect the terms of existing guarantee arrangements for certain GenOn gas transportation contracts discussed below.

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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. That ruling is subject to appeal. CenterPoint Energy and CES intend to continue vigorously defending against the plaintiffs’ claims. CenterPoint Energy does not expect the ultimate outcome of this matter to have a material adverse effect on its financial condition, results of operations or cash flows.

Environmental Matters

Manufactured Gas Plant 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 June 30, 2016, 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.

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.


(c)	Guarantees

Prior to the distribution of CenterPoint Energy’s ownership in RRI to its shareholders, CERC had guaranteed certain contractual obligations of what became RRI’s trading subsidiary. When the companies separated, RRI agreed to secure CERC against obligations under the guarantees RRI had been unable to extinguish by the time of separation. Pursuant to such agreement, as amended in December 2007, RRI (now GenOn) agreed to provide to CERC cash or letters of credit as security against CERC’s obligations under its remaining guarantees for demand charges under certain gas transportation agreements if and to the extent changes in market conditions expose CERC to a risk of loss on those guarantees based on an annual calculation, with any required collateral to be posted each December. The undiscounted maximum potential payout of the demand charges under these

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transportation contracts, which will be in effect until 2018, was approximately $20 million as of June 30, 2016. Based on market conditions in the fourth quarter of 2015 at the time the most recent annual calculation was made under the agreement, GenOn was not obligated to post any security. If GenOn should fail to perform the contractual obligations, CERC could have to honor its guarantee and, in such event, any collateral then provided as security may be insufficient to satisfy CERC’s obligations.

In 2010, CenterPoint Energy provided a guarantee (the CenterPoint Midstream Guarantee) with respect to the performance of certain obligations of Enable under a long-term gas gathering and treating agreement with an indirect, wholly-owned subsidiary of Royal Dutch Shell plc. Under the terms of the omnibus agreement entered into in connection with the closing of the formation of Enable, Enable and CenterPoint Energy have agreed to use commercially reasonable efforts and cooperate with each other to terminate the CenterPoint Midstream Guarantee and to release CenterPoint Energy from such guarantee. As of June 30, 2016, CenterPoint Energy had guaranteed Enable’s obligations up to an aggregate amount of $50 million under the CenterPoint Midstream Guarantee.

CERC Corp. had also provided a guarantee of collection of $1.1 billion of Enable’s senior notes due 2019 and 2024. This guarantee was subordinated to all senior debt of CERC Corp. and was automatically released on May 1, 2016.

The fair value of these guarantees is not material.

(15) Earnings Per Share

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2016				2015		2016		2015
	(in millions, except share and per share amounts)
Net income (loss)	$	(2	)		$	77	$	152	$	208

Basic weighted average shares outstanding	430,653,000				430,235,000		430,530,000		430,096,000
Plus: Incremental shares from assumed conversions:
Restricted stock	—			(1)	1,498,000		2,443,000		1,498,000
Diluted weighted average shares	430,653,000				431,733,000		432,973,000		431,594,000

Basic earnings (loss) per share
Net income (loss)	$	(0.01	)		$	0.18	$	0.35	$	0.48

Diluted earnings (loss) per share
Net income (loss)	$	(0.01	)		$	0.18	$	0.35	$	0.48


(1)	2,443,000 incremental shares from assumed conversions of restricted stock have not been included in the computation of diluted earnings (loss) per share for the three months months ended June 30, 2016, as their inclusion would be anti-dilutive.

(16) 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.

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 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 investment in Enable. Other Operations consists primarily of other corporate operations which support all of CenterPoint Energy’s business operations.

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Financial data for business segments is as follows:



	For the Three Months Ended June 30, 2016
	Revenues from External Customers			Net Intersegment Revenues			Operating Income
	(in millions)
Electric Transmission & Distribution	$	763	(1)	$	—		$	158
Natural Gas Distribution	414			7			20
Energy Services	393			4			—
Midstream Investments (2)	—			—			—
Other Operations	4			—			4
Eliminations	—			(11		)	—
Consolidated	$	1,574		$	—		$	182



	For the Three Months Ended June 30, 2015
	Revenues from External Customers			Net Intersegment Revenues			Operating Income
	(in millions)
Electric Transmission & Distribution	$	705	(1)	$	—		$	158
Natural Gas Distribution	420			7			19
Energy Services	404			4			9
Midstream Investments (2)	—			—			—
Other Operations	3			—			—
Eliminations	—			(11		)	—
Consolidated	$	1,532		$	—		$	186



	For the Six Months Ended June 30, 2016
	Revenues from External Customers			Net Intersegment Revenues			Operating Income		Total Assets as of June 30, 2016
	(in millions)
Electric Transmission & Distribution	$	1,423	(1)	$	—		$	241	$	10,065
Natural Gas Distribution	1,302			14			180		5,585
Energy Services	825			11			6		973
Midstream Investments (2)	—			—			—		2,536
Other Operations	8			—			5		2,771			(3)
Eliminations	—			(25		)	—		(918		)
Consolidated	$	3,558		$	—		$	432	$	21,012



	For the Six Months Ended June 30, 2015
	Revenues from External Customers			Net Intersegment Revenues			Operating Income		Total Assets as of December 31, 2015
	(in millions)
Electric Transmission & Distribution	$	1,317	(1)	$	—		$	254	$	10,028
Natural Gas Distribution	1,605			15			165		5,657
Energy Services	1,036			22			22		857
Midstream Investments (2)	—			—			—		2,594
Other Operations	7			—			1		2,879			(3)
Eliminations	—			(37		)	—		(725		)
Consolidated	$	3,965		$	—		$	442	$	21,290

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



	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
	(in millions)
Affiliates of NRG	$	159	$	172	$	304	$	356
Affiliates of Energy Future Holdings Corp.	$	50	$	51	$	95	$	103


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



	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
	(in millions)
Enable	$	31	$	43	$	91	$	95

Midstream Investments’ total assets are as follows:



	June 30, 2016		December 31, 2015
	(in millions)
Enable	$	2,536	$	2,594


(3)	Included in total assets of Other Operations as of June 30, 2016 and December 31, 2015 are pension and other postemployment-related regulatory assets of $791 million and $814 million, respectively.

(17) Subsequent Events

On July 28, 2016, CenterPoint Energy’s board of directors declared a regular quarterly cash dividend of $0.2575 per share of common stock payable on September 9, 2016, to shareholders of record as of the close of business on August 16, 2016.

On August 2, 2016, Enable declared a quarterly cash distribution of $0.318 per unit on all of its outstanding common and subordinated units for the quarter ended June 30, 2016. Accordingly, CERC Corp. expects to receive a cash distribution of approximately $74 million from Enable in the third quarter of 2016 to be made with respect to CERC Corp.’s investment in common and subordinated units in Enable for the second quarter of 2016.

On August 2, 2016, Enable declared a quarterly cash distribution of $0.625 per Series A Preferred Unit for the quarter ended June 30, 2016. Accordingly, CenterPoint Energy expects to receive a cash distribution of approximately $9 million from Enable in the third quarter of 2016 to be made with respect to CenterPoint Energy’s investment in Series A Preferred Units of Enable for the second quarter of 2016.

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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 2015 Form 10-K.

RECENT EVENTS

Continuum Acquisition. On April 1, 2016, CES, our indirect, wholly-owned subsidiary, closed the previously announced agreement to acquire the retail energy services business and natural gas wholesale assets of Continuum for $98 million. For more information regarding the acquisition, see Note 3 of our Interim Condensed Financial Statements.

Charter Merger. On May 26, 2015, Charter announced that it had entered into a definitive merger agreement with TWC. On September 21, 2015, Charter shareholders approved the announced transaction with TWC. Pursuant to the merger agreement, upon closing of the merger, TWC Common would be exchanged for cash and Charter Common. The merger closed on May 18, 2016. For further information regarding the Charter merger, see Note 11 to our Interim Condensed Financial Statements.

DCRF. In April 2016, Houston Electric filed an application with the Texas Utility Commission for a DCRF interim rate adjustment to account for changes in certain distribution-invested capital since its 2010 rate case. The application requested the annualized DCRF charge to be set at $49.4 million. This charge, effective September 1, 2016 through August 31, 2017, is based on an increase in eligible distribution-invested capital from January 1, 2010 through December 31, 2015 of $689 million. In June 2016, the parties reached a settlement providing for an annualized DCRF charge of $45 million effective September 2016 and, unless otherwise changed in a subsequent DCRF filing, an annualized DCRF charge of $49 million effective September 2017. In July 2016, the Texas Utility Commission approved the settlement.

Houston, South Texas, Beaumont/East Texas and Texas Coast GRIP. NGD’s Houston, South Texas, Beaumont/East Texas and Texas Coast divisions each submitted annual GRIP filings in March 2016 representing an aggregate increase in revenue of $18.2 million based on incremental capital expenditures of $115.5 million. For each division, rates were approved and implemented by July 2016.

Minnesota Rate Case. In August 2015, NGD filed a general rate case with the MPUC requesting an annual increase of $54.1 million. In September 2015, the MPUC approved an interim increase of $47.8 million in revenues effective October 2, 2015, subject to a refund. The MPUC order was issued in June 2016 authorizing a $27.5 million rate adjustment based on an ROE of 9.49% and an ROR of 7.07%. On June 23, 2016, NGD filed a request for reconsideration. The MPUC has 60 days to take action or the reconsideration request is deemed denied by operation of law. The interim rate refund and final rates can only be implemented after the required compliance filing is accepted by the MPUC.

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CONSOLIDATED RESULTS OF OPERATIONS

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
Revenues	$	1,574		$	1,532		$	3,558		$	3,965
Expenses	1,392			1,346			3,126			3,523
Operating Income	182			186			432			442
Interest and Other Finance Charges	(86		)	(89		)	(173		)	(178		)
Interest on Securitization Bonds	(23		)	(27		)	(47		)	(55		)
Equity in Earnings of Unconsolidated Affiliate, net	31			43			91			95
Other Income, net	(96		)	1			(55		)	19
Income Before Income Taxes	8			114			248			323
Income Tax Expense	10			37			96			115
Net Income (Loss)	$	(2	)	$	77		$	152		$	208

Basic Earnings (Loss) Per Share	$	(0.01	)	$	0.18		$	0.35		$	0.48

Diluted Earnings (Loss) Per Share	$	(0.01	)	$	0.18		$	0.35		$	0.48

Three months ended June 30, 2016 compared to three months ended June 30, 2015

We reported a net loss of $2 million ($(0.01) per diluted share) for the three months ended June 30, 2016 compared to net income of $77 million ($0.18 per diluted share) for the same period in 2015.

The decrease in net income of $79 million was due to the following key factors:


•	a $59 million decrease in the gain on marketable securities included in Other Income, net shown above;


•	a $39 million increase in the loss on indexed debt securities related to the ZENS included in Other Income, net shown above, resulting from a loss of $117 million from the Charter merger in 2016 compared to a loss of $7 million from Verizon’s acquisition of AOL in 2015, partially offset by decreased losses of $71 million in the underlying value of the indexed debt securities;


•	a $12 million decrease in equity earnings from our investment in Enable; and


•	a $4 million decrease in operating income (discussed by segment below).

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

•a $27 million decrease in income tax expense;

•a $4 million decrease in interest expense related to lower outstanding balances of our Securitization Bonds;

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

•a $1 million increase in other income included in Other Income, net shown above.

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Six months ended June 30, 2016 compared to six months ended June 30, 2015

We reported net income of $152 million ($0.35 per diluted share) for the six months ended June 30, 2016 compared to net income of $208 million ($0.48 per diluted share) for the same period in 2015.

The decrease in net income of $56 million was due to the following key factors:


•	a $119 million increase in the loss on indexed debt securities related to the ZENS included in Other Income, net shown above, resulting from a loss of $117 million from the Charter merger in 2016 compared to a loss of $7 million from Verizon’s acquisition of AOL in 2015, partially offset by increased losses of $9 million in the underlying value of the indexed debt securities;


•	a $10 million decrease in operating income (discussed by segment below);


•	a $4 million decrease in equity earnings from our investment in Enable; and


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

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


•	a $48 million increase in the gain on marketable securities included in Other Income, net shown above;

•a $19 million decrease in income tax expense;

•an $8 million decrease in interest expense related to lower outstanding balances of our Securitization Bonds; and

•a $5 million decrease in interest expense due to lower weighted average interest rates on outstanding debt.

Income Tax Expense

Our effective tax rate reported for the three months ended June 30, 2016 was 125% compared to 32% for the same period in 2015. The higher effective tax rate for the three months ended June 30, 2016 is due to a Louisiana state tax law change resulting in an increase to our deferred tax liability, the effect of which was compounded by lower earnings. The effective tax rate reported for the six months ended June 30, 2016 was 39% compared to 36% for the same period in 2015. The higher effective tax rate for the six months ended June 30, 2016 is due to a Louisiana state tax law change discussed above. We expect our annual effective tax rate for the period ended December 31, 2016 to be approximately 37%.

RESULTS OF OPERATIONS BY BUSINESS SEGMENT

The following table presents operating income for each of our business segments for the three and six months ended June 30, 2016 and 2015. 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 June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
	(in millions)
Electric Transmission & Distribution	$	158	$	158	$	241	$	254
Natural Gas Distribution	20		19		180		165
Energy Services	—		9		6		22
Other Operations	4		—		5		1
Total Consolidated Operating Income	$	182	$	186	$	432	$	442

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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 2015 Form 10-K.

The following table provides summary data of our Electric Transmission & Distribution business segment for the three and six months ended June 30, 2016 and 2015:



	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
	(in millions, except throughput and customer data)
Revenues:
TDU	$	616	$	585	$	1,156	$	1,099
Bond Companies	147		120		267		218
Total revenues	763		705		1,423		1,317
Expenses:
Operation and maintenance, excluding Bond Companies	330		315		659		622
Depreciation and amortization, excluding Bond Companies	94		84		189		167
Taxes other than income taxes	57		55		114		111
Bond Companies	124		93		220		163
Total expenses	605		547		1,182		1,063
Operating Income	$	158	$	158	$	241	$	254
Operating Income:
TDU	$	135	$	131	$	194	$	199
Bond Companies (1)	23		27		47		55
Total segment operating income	$	158	$	158	$	241	$	254
Throughput (in GWh):
Residential	7,632		7,483		12,651		12,896
Total	22,190		21,751		40,321		39,766
Number of metered customers at end of period:
Residential	2,106,396		2,054,777		2,106,396		2,054,777
Total	2,377,352		2,322,164		2,377,352		2,322,164


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

Three months ended June 30, 2016 compared to three months ended June 30, 2015

Our Electric Transmission & Distribution business segment reported operating income of $158 million for the three months ended June 30, 2016, consisting of $135 million from the TDU and $23 million related to Bond Companies. For the three months ended June 30, 2015, operating income totaled $158 million, consisting of $131 million from the TDU and $27 million related to Bond Companies.

TDU operating income increased $4 million due to the following key factors:


•	higher transmission-related revenues of $20 million, which were partially offset by increased transmission costs billed by transmission providers of $12 million;


•	customer growth of $8 million from the addition of over 55,000 new customers;


•	higher equity return of $5 million, primarily related to true-up proceeds; and

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•	higher right-of-way revenues of $1 million.

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


•	higher depreciation, primarily due to ongoing additions to plant in service, and other taxes of $12 million;


•	lower usage of $4 million, primarily due to milder weather; and


•	higher operation and maintenance expenses of $3 million.

Six months ended June 30, 2016 compared to six months ended June 30, 2015

Our Electric Transmission & Distribution business segment reported operating income of $241 million for the six months ended June 30, 2016, consisting of $194 million from the TDU and $47 million related to Bond Companies. For the six months ended June 30, 2015, operating income totaled $254 million, consisting of $199 million from the TDU and $55 million related to Bond Companies.

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


•	higher depreciation, primarily due to ongoing additions to plant in service, and other taxes of $25 million;


•	higher operation and maintenance expenses of $9 million;


•	lower usage of $7 million, primarily due to milder weather;


•	lower right-of-way revenue of $5 million; and


•	energy efficiency of $1 million due to amortization of the remand bonus recognized in 2015.

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


•	higher transmission-related revenues of $47 million, which were partially offset by increased transmission costs billed by transmission providers of $28 million;


•	customer growth of $14 million from the addition of over 55,000 new customers; and


•	higher equity return of $10 million, primarily related to true-up proceeds.

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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 2015 Form 10-K.

The following table provides summary data of our Natural Gas Distribution business segment for the three and six months ended June 30, 2016 and 2015:



	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
	(in millions, except throughput and customer data)
Revenues	$	421	$	427	$	1,316	$	1,620
Expenses:
Natural gas	130		152		575		908
Operation and maintenance	178		169		367		355
Depreciation and amortization	60		55		119		110
Taxes other than income taxes	33		32		75		82
Total expenses	401		408		1,136		1,455
Operating Income	$	20	$	19	$	180	$	165
Throughput (in Bcf):
Residential	20		19		93		116
Commercial and industrial	56		56		142		144
Total Throughput	76		75		235		260
Number of customers at end of period:
Residential	3,145,655		3,112,902		3,145,655		3,112,902
Commercial and industrial	252,172		249,142		252,172		249,142
Total	3,397,827		3,362,044		3,397,827		3,362,044

Three months ended June 30, 2016 compared to three months ended June 30, 2015

Our Natural Gas Distribution business segment reported operating income of $20 million for the three months ended June 30, 2016, compared to $19 million for the three months ended June 30, 2015.

Operating income increased $1 million as a result of the following key factors:


•	rate increases of $9 million;


•	increased miscellaneous revenues of $4 million, primarily due to weather-related decoupling and increased usage due to improved economic activity in Minnesota; and


•	customer growth of $2 million from the addition of approximately 36,000 new customers.

These increases were partially offset by the following:


•	higher depreciation, primarily due to ongoing additions to plant in service, and other taxes of $7 million;


•	increased contractor services expense of $5 million, primarily due to pipeline integrity work and higher disconnect activities that are recovered when service is reconnected; and


•	increased labor and benefits expense of $2 million.

Increased expense related to energy efficiency programs of $1 million and decreased expense related to gross receipt taxes of $1 million were offset by corresponding offsets in the related revenues.

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Six months ended June 30, 2016 compared to six months ended June 30, 2015

Our Natural Gas Distribution business segment reported operating income of $180 million for the six months ended June 30, 2016, compared to $165 million for the six months ended June 30, 2015.

Operating income increased $15 million as a result of the following key factors:


•	rate increases of $31 million; and


•	customer growth of $3 million from the addition of approximately 36,000 new customers.

These increases were partially offset by the following:


•	higher depreciation, primarily due to ongoing additions to plant in service, and other taxes of $10 million;


•	increased contractor services expense of $6 million, primarily due to pipeline integrity work and higher disconnect activities that are recovered when service is reconnected; and


•	increased labor and benefits expense of $4 million.

Decreased expense related to gross receipt taxes of $8 million were offset by a corresponding decrease in the related revenues.

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 2015 Form 10-K.

The following table provides summary data of our Energy Services business segment for the three and six months ended June 30, 2016 and 2015:



	Three Months Ended June 30,					Six Months Ended June 30,
	2016			2015		2016			2015
	(in millions, except throughput and customer data)
Revenues	$	397		$	408	$	836		$	1,058
Expenses:
Natural gas	377			388		798			1,012
Operation and maintenance	17			9		27			21
Depreciation and amortization	3			1		4			2
Taxes other than income taxes	—			1		1			1
Total expenses	397			399		830			1,036
Operating Income	$	—		$	9	$	6		$	22

Mark-to-market gain (loss)	$	(7	)	$	2	$	(16	)	$	(2	)

Throughput (in Bcf)	199			136		370			321

Number of customers at end of period	30,675			18,073		30,675			18,073

Three months ended June 30, 2016 compared to three months ended June 30, 2015

Our Energy Services business segment reported operating income of $-0- for the three months ended June 30, 2016 compared to $9 million for the three months ended June 30, 2015. The decrease in operating income of $9 million was primarily due to a

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$9 million decrease from mark-to-market accounting for derivatives associated with certain natural gas purchases and sales used to lock in economic margins. The second quarter of 2016 included a $7 million mark-to-market charge compared to a $2 million mark-to-market benefit for the same period of 2015. The second quarter of 2016 also included $2 million of operation and maintenance expenses and $1 million of amortization expenses related to the acquisition and integration of Continuum.

Six months ended June 30, 2016 compared to six months ended June 30, 2015

Our Energy Services business segment reported operating income of $6 million for the six months ended June 30, 2016 compared to $22 million for the six months ended June 30, 2015. The decrease in operating income of $16 million was primarily due to a $14 million decrease from mark-to-market accounting for derivatives associated with certain natural gas purchases and sales used to lock in economic margins. The first half of 2016 included a $16 million mark-to-market charge compared to a $2 million mark-to-market charge for the same period of 2015. The six months ended June 30, 2016 also included $2 million of operation and maintenance expenses and $1 million of amortization expenses related to the acquisition and integration of Continuum. The remaining decrease in operating income was margin related, resulting primarily from reduced weather-related optimization opportunities of existing gas transportation assets.

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 2015 Form 10-K.

The following table provides pre-tax equity income of our Midstream Investments business segment for the three and six months ended June 30, 2016 and 2015:



	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
	(in millions)
Enable	$	31	$	43	$	91	$	95

Other Operations

The following table shows the operating income of our Other Operations business segment for the three and six months ended June 30, 2016 and 2015:



	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
	(in millions)
Revenues	$	4	$	3	$	8	$	7
Expenses	—		3		3		6
Operating Income	$	4	$	—	$	5	$	1

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 2015 Form 10-K, “Risk Factors” in Item 1A of Part I of our 2015 Form 10-K and “Cautionary Statement Regarding Forward-Looking Information” in this Form 10-Q.

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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 six months ended June 30, 2016 and 2015:



	Six Months Ended June 30,
	2016			2015
	(in millions)
Cash provided by (used in):
Operating activities	$	1,058		$	1,122
Investing activities	(467		)	(671		)
Financing activities	(584		)	(504		)

Cash Provided by Operating Activities

Net cash provided by operating activities in the first six months of 2016 decreased $64 million compared to the same period in 2015 due to changes in working capital ($138 million), partially offset by higher net income after adjusting for non-cash and non-operating items ($50 million) (primarily depreciation and amortization and deferred income taxes) and increased cash from other non-current items ($24 million). The changes in working capital items in 2016 primarily related to decreased cash provided by fuel cost over recovery, natural gas storage inventory and net regulatory assets and liabilities, partially offset by increased cash provided by non-trading derivatives, net and margin deposits, net.

Cash Used in Investing Activities

Net cash used in investing activities in the first six months of 2016 decreased $204 million compared to the same period in 2015 due primarily to increased cash received for the repayment of notes receivable from Enable ($363 million), a return of capital from Enable ($149 million), increased proceeds from the sale of marketable securities associated with the Charter merger ($146 million) and decreased capital expenditures ($30 million), which were partially offset by increased cash used for the purchase of Series A Preferred Units ($363 million), increased cash used for the Continuum acquisition ($98 million) and increased restricted cash ($15 million).

Cash Used in Financing Activities

Net cash used by financing activities in the first six months of 2016 increased $80 million compared to the same period in 2015 due to increased payments of long-term debt ($335 million), increased distributions to ZENS note holders ($178 million), increased payment of common stock dividends ($8 million) and increased debt issuance costs ($7 million), which were partially offset by increased proceeds from the issuance of general mortgage bonds ($300 million), increased net proceeds from commercial paper ($141 million) and decreased short-term borrowings ($6 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 six months of 2016 include the following:


•	capital expenditures of approximately $695 million;


•	scheduled principal payments on Securitization Bonds of $183 million;


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


•	interest payments on debt.

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We expect that borrowings under our credit facilities, proceeds from commercial paper, proceeds from the issuance of general mortgage bonds, anticipated cash flows from operations and distributions from Enable will be sufficient to meet our anticipated cash needs for the remaining six months of 2016. 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

Prior to the distribution of our ownership in RRI to our shareholders, CERC had guaranteed certain contractual obligations of what became RRI’s trading subsidiary. When the companies separated, RRI agreed to secure CERC against obligations under the guarantees RRI had been unable to extinguish by the time of separation. Pursuant to such agreement, as amended in December 2007, RRI (now GenOn) agreed to provide to CERC cash or letters of credit as security against CERC’s obligations under its remaining guarantees for demand charges under certain gas transportation agreements if and to the extent changes in market conditions expose CERC to a risk of loss on those guarantees based on an annual calculation, with any required collateral to be posted each December. The undiscounted maximum potential payout of the demand charges under these transportation contracts, which will be in effect until 2018, was approximately $20 million as of June 30, 2016. Based on market conditions in the fourth quarter of 2015 at the time the most recent annual calculation was made under the agreement, GenOn was not obligated to post any security. If GenOn should fail to perform the contractual obligations, CERC could have to honor its guarantee and, in such event, any collateral provided as security may be insufficient to satisfy CERC’s obligations.

In 2010, CenterPoint Energy provided a guarantee (the CenterPoint Midstream Guarantee) with respect to the performance of certain obligations of Enable under a long-term gas gathering and treating agreement with an indirect, wholly-owned subsidiary of Royal Dutch Shell plc. Under the terms of the omnibus agreement entered into in connection with the closing of the formation of Enable, Enable and CenterPoint Energy have agreed to use commercially reasonable efforts and cooperate with each other to terminate the CenterPoint Midstream Guarantee and to release CenterPoint Energy from such guarantee. As of June 30, 2016, we have guaranteed Enable’s obligations up to an aggregate amount of $50 million under the CenterPoint Midstream Guarantee.

The fair value of these guarantees is not material. Other than the guarantees described above and operating leases, we have no off-balance sheet arrangements.

Regulatory Matters

Significant regulatory developments that have occurred since our 2015 Form 10-K was filed with the SEC are discussed below.

Houston Electric

Brazos Valley Connection Project. In April 2016, the Texas Utility Commission issued an order on rehearing for the Brazos Valley Connection requiring Houston Electric to use steel monopoles in lieu of lattice towers for the construction to reduce the aesthetic impact of the project. The Texas Utility Commission’s original order provided an estimated range of approximately $270–$310 million for the capital costs for the Brazos Valley Connection. The actual cost will depend on factors including land acquisition costs, material and construction costs, and other factors. Houston Electric expects to complete construction of the Brazos Valley Connection by mid-2018.

EECRF. In June 2016, Houston Electric filed an application with the Texas Utility Commission for an adjustment to its EECRF to recover $45.9 million in 2017, including an incentive of $10.6 million based on 2015 program performance. Houston Electric requested approval effective by March 2017.

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TCOS. In July 2016, Houston Electric filed an application with the Texas Utility Commission for an interim update of its TCOS seeking an increase in annual revenues based on an incremental increase in total rate base of $95.6 million. Houston Electric expects to receive approval from the Texas Utility Commission during the third quarter of 2016. An increase of $3.5 million in annual revenues is expected based on this approval.

CERC

Houston, South Texas, Beaumont/East Texas and Texas Coast GRIP. NGD’s Houston, South Texas, Beaumont/East Texas and Texas Coast divisions each submitted annual GRIP filings on March 31, 2016 representing an aggregate increase in revenue of $18.2 million based on incremental capital expenditures of $115.5 million. For each division, rates were approved and implemented by July 2016.

Oklahoma PBRC. In March 2016, NGD made a PBRC filing for the 2015 calendar year proposing to increase revenues by $0.5 million. On July 19, 2016, the Oklahoma Corporation Commission approved a joint stipulation that provides for a 10% ROE, a capital structure of 45% debt and 55% equity and no change in rates.

Arkansas BDA. In March 2016, NGD made its annual BDA filing with the APSC to request recovery of a calendar year 2015 shortfall of $5.5 million. Rates were implemented in June 2016.

Arkansas Rate Case. In November 2015, NGD filed an Application for Approval of a General Change in Rates with the APSC seeking a $35.6 million increase in revenue requirement and a 10.3% ROE. A non-unanimous settlement agreement was reached with the APSC staff and certain other parties for an annual revenue increase of $14.2 million and a 9.5% ROE plus the adoption of an annual rate mechanism to recover future capital and expenses. A hearing was held in July 2016 for the APSC to consider the non-unanimous settlement. A final determination by the APSC is expected in the third quarter of 2016.

Louisiana RSP. NGD made its 2015 Louisiana RSP filings with the LPSC in October 2015. The North Louisiana Rider RSP filing shows a revenue deficiency of $1.0 million, and the South Louisiana Rider RSP filing shows a revenue deficiency of $1.5 million. Both 2015 Louisiana RSP filings utilized the capital structure and ROE factors approved by the LPSC in September 2015, which set an authorized ROE of 9.95% and a capital structure of 48% debt and 52% equity. NGD began billing in December 2015, subject to a refund. The 2015 Louisiana RSP filing is still subject to final approval from the LPSC. NGD made its 2014 Louisiana RSP filings with the LPSC in October 2014. The North Louisiana Rider RSP filing showed a revenue deficiency of $4.0 million, using the then-authorized ROE of 10.25% with a capital structure of 53% debt and 47% equity. The South Louisiana Rider RSP filing showed a revenue deficiency of $2.3 million, using the then-authorized ROE of 10.5% with a capital structure of 53% debt and 47% equity. NGD began billing the revised rates in December 2014, subject to refund or surcharge. After LPSC staff review and adjustments to conform to the RSP changes ordered by the LPSC in the 2013 RSP cases as approved in September 2015, NGD settled on an adjustment for the North Louisiana Rider RSP of $4.7 million, with an authorized ROE of 9.95% and a capital structure of 48% debt and 52% equity. NGD also settled on an adjustment for the South Louisiana Rider RSP of $2.5 million, with an authorized ROE of 9.95% and a capital structure of 48% debt and 52% equity. The settlements were approved by the LPSC and rates were implemented in July 2016.

Minnesota CIP. In May 2016, NGD filed a CIP request with the MPUC, seeking a $12.7 million financial incentive based on 2015 program performance. This request is currently pending approval from the MPUC and will be recognized when approved.

Mississippi RRA. In April 2016, NGD filed for a $3.5 million RRA with the MPSC, which was subsequently revised to a $3.3 million RRA with an adjusted ROE of 9.47%. The filing is currently pending approval from the MPSC. New rates are expected to be implemented in the third quarter of 2016.

PHMSA Regulatory Proposals. Recent regulatory proposals from the U.S. Department of Transportation’s PHMSA would expand the scope of its safety, reporting, and recordkeeping requirements for both natural gas and hazardous liquids (including oil and NGLs) pipelines. These proposals, if finalized, would impose additional costs on us and Enable.

In March 2016, PHMSA issued a notice of proposed rulemaking detailing proposed revisions to the safety standards applicable to natural gas transmission and gathering pipelines. The proposed rules would add requirements for pipelines already subject to

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integrity management requirements, including repair criteria for pipelines in high consequence areas and requirements for monitoring gas quality and managing corrosion. For pipelines not already subject to integrity management requirements, the proposed rules include a new moderate consequence area definition, require gas quality monitoring and corrosion management, establish repair criteria and require verification of certain pipeline parameters. The proposed rules would also expand the scope of gas gathering lines subject to PHMSA regulation-including imposing minimum safety standards on certain larger, currently exempt, gathering lines-while subjecting all gathering-line operators to recordkeeping and annual reporting requirements from which they are currently exempt. The rules would also require inspections of pipeline areas affected by severe weather, natural disasters or similar events.

PHMSA issued a similar notice of proposed rulemaking for hazardous liquid pipelines in October 2015. The proposed rules would extend PHMSA reporting requirements to all gathering lines, require pipeline inspections in areas affected by extreme weather or natural disasters, require periodic inline inspections of pipelines outside of high consequence areas, require use of leak detection systems on all hazardous liquid pipelines, modify applicable repair criteria and set a timeline for pipelines subject to integrity management requirements to be capable of accommodating inline inspection tools.

Other Matters

Debt Financing Transaction

In May 2016, Houston Electric issued $300 million aggregate principal amount of 1.85% general mortgage bonds due 2021. The proceeds from the issuance of the bonds were used to repay short-term debt and for general corporate purposes.

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 and to backstop the companies’ commercial paper programs. The facilities may also be utilized to obtain letters of credit. As of July 29, 2016, we had the following facilities:



Execution Date	Company	Size of Facility		Amount Utilized at July 29, 2016 (1)			Termination Date
		(in millions)
March 3, 2016	CenterPoint Energy	$	1,600	$	1,013	(2)	March 3, 2021
March 3, 2016	Houston Electric	300		4		(3)	March 3, 2021
March 3, 2016	CERC Corp.	600		221		(4)	March 3, 2021


(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 $2.5 billion as of June 30, 2016.


(2)	Represents outstanding commercial paper of $1,007 million and outstanding letters of credit of $6 million.


(3)	Represents outstanding letters of credit.


(4)	Represents outstanding commercial paper of $217 million and outstanding letters of credit of $4 million.

Our $1.6 billion revolving credit facility, which is scheduled to terminate on March 3, 2021, can be drawn at LIBOR plus 1.25% based on CenterPoint Energy’s current credit ratings. The revolving credit facility contains a financial covenant which limits our consolidated debt (with certain exceptions, including but not limited to Securitization Bonds) to an amount not to exceed 65% of our consolidated capitalization. As of June 30, 2016, our debt (excluding Securitization Bonds) to capital ratio, as defined in its credit facility agreement, was 55.5%. 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 we certify to the administrative agent that Houston Electric has incurred system restoration costs reasonably likely to exceed $100 million in a consecutive twelve-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 we deliver our certification until the earliest to occur of (i) the completion of the securitization financing, (ii) the first anniversary of our certification or (iii) the revocation of such certification.

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an amount not to exceed 65% of Houston Electric’s consolidated capitalization. As of June 30, 2016, Houston Electric’s debt (excluding Securitization Bonds) to capital ratio, as defined in its credit facility agreement, was 52.7%. 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 Houston Electric certifies to the administrative agent that Houston Electric has incurred system restoration costs reasonably likely to exceed $100 million in a consecutive twelve-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 Houston Electric delivers its certification until the earliest to occur of (i) the completion of the securitization financing, (ii) the first anniversary of Houston Electric’s certification or (iii) the revocation of such certification.

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.

On April 4, 2016, in connection with the replacement of our $1.2 billion unsecured revolving credit facility with the new $1.6 billion facility, we increased the size of our commercial paper program to permit the issuance of commercial paper notes in an aggregate principal amount not to exceed the unused portion of our $1.6 billion facility. The size of CERC Corp.’s commercial paper program will remain at $600 million. Our $1.6 billion revolving credit facility backstops our $1.6 billion commercial paper program. CERC Corp.’s $600 million revolving credit facility backstops its $600 million commercial paper program.

Securities Registered with the SEC

CenterPoint Energy, Houston Electric and CERC Corp. have 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.

Temporary Investments

As of July 29, 2016, we had no temporary external investments.

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.

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Impact on Liquidity of a Downgrade in Credit Ratings

The interest on borrowings under our credit facilities is based on our credit rating. As of July 29, 2016, 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+

Negative

BBB

Stable

Houston Electric Senior
Secured Debt

Stable

Negative

Stable

CERC Corp. Senior Unsecured

Debt

Baa2

Stable

A-

Negative

BBB

Stable


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


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


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

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 from Moody’s or S&P could increase borrowing costs under our $1.6 billion revolving credit facility, Houston Electric’s $300 million revolving credit facility and CERC Corp.’s $600 million revolving credit facility. If our credit ratings or those of Houston Electric or CERC Corp. had been downgraded one notch by Moody’s and/or S&P from the ratings that existed at June 30, 2016, 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.

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

CES, a wholly-owned subsidiary of CERC Corp. operating in our Energy Services business segment, provides natural gas sales and services primarily to commercial and industrial customers and electric and natural gas utilities throughout the central and eastern United States. To economically hedge its exposure to natural gas prices, CES uses derivatives with provisions standard for the industry, including those pertaining to credit thresholds. Typically, the credit threshold negotiated with each counterparty defines the amount of unsecured credit that such counterparty will extend to CES. To the extent that the credit exposure that a counterparty has to CES at a particular time does not exceed that credit threshold, CES is not obligated to provide collateral. Mark-to-market exposure in excess of the credit threshold is routinely collateralized by CES. As of June 30, 2016, the amount posted as collateral aggregated approximately $22 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 June 30, 2016, unsecured credit limits extended to CES by counterparties aggregated $367 million, and $2 million of such amount was utilized.

Pipeline tariffs and contracts typically provide that if the credit ratings of a shipper or the shipper’s guarantor drop below a threshold level, which is generally investment grade ratings from both Moody’s and S&P, cash or other collateral may be demanded from the shipper in an amount equal to the sum of three months’ charges for pipeline services plus the unrecouped cost of any lateral built for such shipper. If the credit ratings of CERC Corp. decline below the applicable threshold levels, CERC Corp. might need to provide cash or other collateral of as much as $158 million as of June 30, 2016. The amount of collateral will depend on seasonal variations in transportation levels.

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ZENS and Securities Related to ZENS

In September 1999, we issued ZENS having an original principal amount of $1.0 billion of which $828 million remains outstanding as of June 30, 2016. Each ZENS note was originally exchangeable at the holder’s option at any time for an amount of cash equal to 95% of the market value of the reference shares of TW Common attributable to such note. The number and identity of the reference shares attributable to each ZENS note are adjusted for certain corporate events. As of June 30, 2016, the reference shares for each ZENS note 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 amount was $519 million.

If our creditworthiness were to drop such that ZENS note holders thought our liquidity was adversely affected or the market for the ZENS notes were to become illiquid, some ZENS note holders might decide to exchange their ZENS notes for cash. Funds for the payment of cash upon exchange could be obtained from the sale of the shares of TW Common, Charter Common and Time Common that we own or from other sources. We own shares of TW Common, Charter Common and Time Common equal to approximately 100% of the reference shares used to calculate our obligation to the holders of the ZENS notes. ZENS note exchanges result in a cash outflow because tax deferrals related to the ZENS notes and TW Common, Charter Common and Time Common shares would typically cease when ZENS notes are exchanged or otherwise retired and TW Common, Charter Common and Time Common shares are sold. The ultimate tax liability related to the ZENS notes continues to increase by the amount of the tax benefit realized each year, and there could be a significant cash outflow when the taxes are paid as a result of the retirement of the ZENS notes. If all ZENS notes had been exchanged for cash on June 30, 2016, deferred taxes of approximately $501 million would have been payable in 2016. If all the TW Common, Charter Common and Time Common had been sold on June 30, 2016, capital gains taxes of approximately $212 million would have been payable in 2016.

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.

Enable Midstream Partners

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

Enable is expected to pay a minimum quarterly distribution of $0.2875 per 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 (referred to as “available cash”) within 60 days after the end of each quarter. On August 2, 2016, Enable declared a quarterly cash distribution of $0.318 per unit on all of its outstanding common and subordinated units for the quarter ended June 30, 2016. Accordingly, CERC Corp. expects to receive a cash distribution of approximately $74 million

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from Enable in the third quarter of 2016 to be made with respect to CERC Corp.’s limited partner interest in Enable for the second quarter of 2016.

Hedging of Interest Expense for Future Debt Issuances

In April 2016, 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 5-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 May 2016. These forward interest rate agreements were designated as cash flow hedges. Accordingly, the ineffective portion of unrealized gains and losses associated with the agreements was recorded in income and was immaterial.

Weather Hedge

We have weather normalization or other rate mechanisms that mitigate the impact of weather on NGD in Arkansas, Louisiana, Mississippi, Minnesota and Oklahoma. NGD and electric operations in Texas do not have such mechanisms, although fixed customer charges are historically higher in Texas for NGD compared to our other jurisdictions. As a result, fluctuations from normal weather may have a positive or negative effect on NGD’s results in Texas and on Houston Electric’s results in its service territory. We have historically entered into heating-degree day swaps for certain NGD jurisdictions to mitigate the effect of fluctuations from normal weather on its results of operations and cash flows for the winter heating season. However, NGD did not enter into heating-degree day swaps for the 2015–2016 winter season as a result of NGD’s Minnesota division implementing a full decoupling pilot in July 2015. We entered into a weather hedge swap pursuant to the Dodd-Frank’s end-user exception for Houston Electric’s service territory for the 2015–2016 winter season.

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 to satisfy their obligations in respect of GenOn’s indemnity obligations to us and our subsidiaries or in connection with the contractual obligations to a third party pursuant to which our subsidiary is their guarantor;

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•	the ability of REPs, including REP affiliates of NRG and Energy Future Holdings 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 and 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 2015 Form 10-K.

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

Houston Electric’s revolving credit facility limits Houston Electric’s consolidated debt (with certain exceptions, including but not limited to Securitization Bonds) to an amount not to exceed 65% of its consolidated capitalization. CERC Corp.’s revolving credit facility limits CERC’s consolidated debt to an amount not to exceed 65% of its consolidated capitalization. Our revolving credit facility limits our consolidated debt (with certain exceptions, including but not limited to Securitization Bonds) to an amount not to exceed 65% of our consolidated capitalization. The financial covenant limit in Houston Electric’s and our revolving credit facilities will temporarily increase from 65% to 70% if Houston Electric experiences damage from a natural disaster in its service territory that meets certain criteria. Additionally, Houston Electric has contractually agreed that it will not issue additional first mortgage bonds, subject to certain exceptions.

NEW ACCOUNTING PRONOUNCEMENTS

See Note 2 to our Interim Condensed Consolidated Financial Statements for a discussion of new accounting pronouncements that affect us.


Item 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk

As of June 30, 2016, we had outstanding long-term debt, bank loans, lease obligations and obligations under our ZENS (indexed debt securities) that subject us to the risk of loss associated with movements in market interest rates.

As of June 30, 2016 and December 31, 2015, our floating-rate obligations aggregated $1.2 billion and $1.1 billion, respectively. If the floating interest rates were to increase by 10% from June 30, 2016 rates, our combined interest expense would increase by approximately $1 million annually.

As of June 30, 2016 and December 31, 2015, we had outstanding fixed-rate debt (excluding indexed debt securities) aggregating $7.3 billion and $7.5 billion, respectively, in principal amount and having a fair value of $8.1 billion and $8.0 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 $193 million if interest rates were to decline by 10% from their levels at June 30, 2016. 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 $111 million as of June 30, 2016 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 $20 million if interest rates were to decline by 10% from levels at June 30, 2016. Changes in the fair value of the derivative component, a liability recorded at $490 million as of June 30, 2016, 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 risk-free interest rate. If the risk-free interest rate were to increase by 10% from June 30, 2016 levels, the fair value of the derivative component would increase by approximately $2 million, which would be recorded as an unrealized loss in our Condensed Statements of Consolidated Income.

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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 June 30, 2016 aggregate market value of these shares would result in a net loss of approximately $7 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 stand-alone commodity risk created by these instruments, without regard to the offsetting effect of the underlying exposure these instruments are intended to hedge, is described below. We measure the commodity risk of our non-trading energy derivatives using a sensitivity analysis. The sensitivity analysis performed on our non-trading energy derivatives measures the potential loss in fair value based on a hypothetical 10% movement in energy prices. As of June 30, 2016, the recorded fair value of our non-trading energy derivatives was a net asset of $46 million (before collateral), all of which is related to our Energy Services business segment. An increase of 10% in the market prices of energy commodities from their June 30, 2016 levels would have decreased the fair value of our non-trading energy derivatives net asset by $9 million.

The above analysis of the non-trading energy derivatives utilized for commodity price risk management purposes does not include the favorable impact that the same hypothetical price movement would have on our non-derivative physical purchases and sales of natural gas to which the hedges relate. Furthermore, the non-trading energy derivative portfolio is managed to complement the physical transaction portfolio, reducing overall risks within limits. Therefore, the adverse impact to the fair value of the portfolio of non-trading energy derivatives held for hedging purposes associated with the hypothetical changes in commodity prices referenced above is expected to be substantially offset by a favorable impact on the underlying hedged physical transactions.


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 June 30, 2016 to provide assurance that information required to be disclosed in our reports filed or submitted under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and 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 June 30, 2016 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 14(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 2015 Form 10-K.


Item 1A.	RISK FACTORS

There have been no material changes from the risk factors disclosed in our 2015 Form 10-K.


Item 5.	OTHER INFORMATION

Ratio of Earnings to Fixed Charges. The ratio of earnings to fixed charges for the six months ended June 30, 2016 and 2015 was 2.35 and 2.53, respectively. We do not believe that the ratios for these six-month periods are necessarily indicative of the ratios for the twelve-month periods due to the seasonal nature of our business. The ratios were calculated pursuant to applicable rules of the SEC.

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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	Second Amended and Restated Bylaws of CenterPoint Energy	CenterPoint Energy’s Form 10-K for the year ended December 31, 2015	1-31447	3(b)
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
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	Twenty-Fourth Supplemental Indenture, dated as of May 18, 2016, to the General Mortgage Indenture, dated as of October 10, 2002, between Houston Electric and the Trustee
+4.6	Officer’s Certificate, dated as of May 18, 2016, setting forth the form, terms and provisions of the Twenty-Fifth Series of General Mortgage Bonds
10.1	Fourth Amended and Restated Agreement of Limited Partnership of Enable Midstream Partners, LP, dated June 22, 2016	CenterPoint Energy’s Form 8-K dated June 22, 2016	1-31447	10.1
10.2	Third Amended and Restated Limited Liability Company Agreement of Enable GP, LLC, dated June 22, 2016	CenterPoint Energy’s Form 8-K dated June 22, 2016	1-31447	10.2
+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

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Exhibit Number	Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference
+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: August 5, 2016

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Index to 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.



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	Second Amended and Restated Bylaws of CenterPoint Energy	CenterPoint Energy’s Form 10-K for the year ended December 31, 2015	1-31447	3(b)
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
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	Twenty-Fourth Supplemental Indenture, dated as of May 18, 2016, to the General Mortgage Indenture, dated as of October 10, 2002, between Houston Electric and the Trustee
+4.6	Officer’s Certificate, dated as of May 18, 2016, setting forth the form, terms and provisions of the Twenty-Fifth Series of General Mortgage Bonds
10.1	Fourth Amended and Restated Agreement of Limited Partnership of Enable Midstream Partners, LP, dated June 22, 2016	CenterPoint Energy’s Form 8-K dated June 22, 2016	1-31447	10.1
10.2	Third Amended and Restated Limited Liability Company Agreement of Enable GP, LLC, dated June 22, 2016	CenterPoint Energy’s Form 8-K dated June 22, 2016	1-31447	10.2
+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

Table of Contents



Exhibit Number	Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference
+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