CENTERPOINT ENERGY INC - FORM 10-Q

Attached files

file	filename
EX-32.2 - EXHIBIT 32.2 - CENTERPOINT ENERGY INC	cnp_exhibit322x9302015.htm
EX-31.1 - EXHIBIT 31.1 - CENTERPOINT ENERGY INC	cnp_exhibit311x9302015.htm
EX-32.1 - EXHIBIT 32.1 - CENTERPOINT ENERGY INC	cnp_exhibit321x9302015.htm
EX-31.2 - EXHIBIT 31.2 - CENTERPOINT ENERGY INC	cnp_exhibit312x9302015.htm
EX-12 - EXHIBIT 12 - CENTERPOINT ENERGY INC	cnp_exhibit12x9302015.htm

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

__________________

FORM 10-Q



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

	FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2015



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 October 23, 2015, CenterPoint Energy, Inc. had 430,262,191 shares of common stock outstanding, excluding 166 shares held as treasury stock.

CENTERPOINT ENERGY, INC.

QUARTERLY REPORT ON FORM 10-Q

FOR THE QUARTER ENDED SEPTEMBER 30, 2015

TABLE OF CONTENTS



PART I.	FINANCIAL INFORMATION

Item 1.	Financial Statements	1

	Condensed Statements of Consolidated Income
	Three and Nine Months Ended September 30, 2015 and 2014 (unaudited)	1

	Condensed Statements of Consolidated Comprehensive Income
	Three and Nine Months Ended September 30, 2015 and 2014 (unaudited)	2

	Condensed Consolidated Balance Sheets
	September 30, 2015 and December 31, 2014 (unaudited)	3

	Condensed Statements of Consolidated Cash Flows
	Nine Months Ended September 30, 2015 and 2014 (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	44

Item 4.	Controls and Procedures	44

PART II.	OTHER INFORMATION

Item 1.	Legal Proceedings	45

Item 1A.	Risk Factors	45

Item 5.	Other Information	45

Item 6.	Exhibits	46

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 Midstream Partners, LP (Enable), the amount of cash distributions we receive from Enable, 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 natural gas liquids (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 growth 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;


•	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;


•	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;


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


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


•	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;


•	our ability to invest planned capital;


•	our ability to control operation and maintenance costs;


•	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;


•	actions by credit rating agencies;


•	inability of various counterparties to meet their obligations to us;


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


•	the ability of retail electric providers (REPs), including REP affiliates of NRG Energy, Inc. (NRG) and Energy Future Holdings Corp., to satisfy their obligations to us and our subsidiaries;


•	our potential business strategies, 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 Energy, Inc. (formerly known as RRI Energy, Inc., Reliant Energy, Inc. and Reliant Resources, Inc.), 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;


•	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;


•	effectiveness of our risk management activities;


•	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 Annual Report on Form 10-K for the year ended December 31, 2014, which is incorporated herein by reference, and other reports we file from time to time with the Securities and Exchange Commission.

You should not place undue reliance on forward-looking statements. Each forward-looking statement speaks only as of the date of the particular statement.

iii

Table of Contents

PART I. FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

CONDENSED STATEMENTS OF CONSOLIDATED INCOME

(In Millions, Except Per Share Amounts)

(Unaudited)



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2015			2014			2015			2014

Revenues	$	1,630		$	1,807		$	5,595		$	6,854

Expenses:
Natural gas	527			702			2,410			3,625
Operation and maintenance	479			493			1,465			1,441
Depreciation and amortization	268			293			724			784
Taxes other than income taxes	91			86			289			290
Total	1,365			1,574			4,888			6,140
Operating Income	265			233			707			714

Other Income (Expense):
Gain (loss) on marketable securities	(134		)	31			(72		)	73
Gain (loss) on indexed debt securities	129			(22		)	62			(29		)
Interest and other finance charges	(88		)	(88		)	(266		)	(261		)
Interest on transition and system restoration bonds	(25		)	(30		)	(80		)	(90		)
Equity in earnings (losses) of unconsolidated affiliates, net	(794		)	79			(699		)	241
Other, net	12			10			36			28
Total	(900		)	(20		)	(1,019		)	(38		)

Income (Loss) Before Income Taxes	(635		)	213			(312		)	676
Income tax expense (benefit)	(244		)	70			(129		)	241
Net Income (Loss)	$	(391	)	$	143		$	(183	)	$	435

Basic Earnings (Loss) Per Share	$	(0.91	)	$	0.33		$	(0.43	)	$	1.01

Diluted Earnings (Loss) Per Share	$	(0.91	)	$	0.33		$	(0.43	)	$	1.01

Dividends Declared Per Share	$	0.2475		$	0.2375		$	0.7425		$	0.7125

Weighted Average Shares Outstanding, Basic	430			430			430			430

Weighted Average Shares Outstanding, Diluted	430			432			430			431

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					Nine Months Ended
	September 30,					September 30,
	2015			2014		2015			2014
Net income (loss)	$	(391	)	$	143	$	(183	)	$	435
Other comprehensive income:
Adjustment related to pension and other postretirement plans (net of tax of $1, $1, $3 and $4)	1			2		5			5
Total	1			2		5			5
Comprehensive income (loss)	$	(390	)	$	145	$	(178	)	$	440

See Notes to Interim Condensed Consolidated Financial Statements

Table of Contents

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(In Millions)

(Unaudited)

ASSETS



	September 30, 2015		December 31, 2014
Current Assets:
Cash and cash equivalents ($215 and $290 related to VIEs, respectively)	$	227	$	298
Investment in marketable securities	826		930
Accounts receivable ($73 and $58 related to VIEs, respectively), less bad debt reserve of $19 and $26, respectively	568		837
Accrued unbilled revenues	180		357
Natural gas inventory	168		211
Materials and supplies	174		168
Non-trading derivative assets	78		99
Taxes receivable	68		190
Prepaid expenses and other current assets ($38 and $47 related to VIEs, respectively)	111		178
Total current assets	2,400		3,268

Property, Plant and Equipment:
Property, plant and equipment	16,264		15,358
Less: accumulated depreciation and amortization	5,079		4,856
Property, plant and equipment, net	11,185		10,502

Other Assets:
Goodwill	840		840
Regulatory assets ($2,465 and $2,738 related to VIEs, respectively)	3,199		3,527
Notes receivable - affiliated companies	363		363
Non-trading derivative assets	39		32
Investment in unconsolidated affiliates	3,604		4,521
Other	148		147
Total other assets	8,193		9,430

Total Assets	$	21,778	$	23,200

See Notes to Interim Condensed Consolidated Financial Statements

Table of Contents

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS – (continued)

(In Millions, except share amounts)

(Unaudited)

LIABILITIES AND SHAREHOLDERS’ EQUITY



	September 30, 2015			December 31, 2014
Current Liabilities:
Short-term borrowings	$	49		$	53
Current portion of VIE transition and system restoration bonds long-term debt	390			372
Indexed debt	152			152
Current portion of other long-term debt	396			271
Indexed debt securities derivative	454			541
Accounts payable	367			716
Taxes accrued	128			161
Interest accrued	118			124
Non-trading derivative liabilities	12			19
Deferred income taxes, net	741			683
Other	384			383
Total current liabilities	3,191			3,475

Other Liabilities:
Deferred income taxes, net	4,445			4,757
Non-trading derivative liabilities	5			1
Benefit obligations	889			953
Regulatory liabilities	1,269			1,206
Other	259			251
Total other liabilities	6,867			7,168

Long-term Debt:
VIE transition and system restoration bonds	2,346			2,674
Other	5,316			5,335
Total long-term debt	7,662			8,009

Commitments and Contingencies (Note 13)

Shareholders’ Equity:
Common stock (430,262,148 shares and 429,795,830 shares outstanding, respectively)	4			4
Additional paid-in capital	4,176			4,169
Retained earnings (accumulated deficit)	(41		)	461
Accumulated other comprehensive loss	(81		)	(86		)
Total shareholders’ equity	4,058			4,548

Total Liabilities and Shareholders’ Equity	$	21,778		$	23,200

See Notes to Interim Condensed Consolidated Financial Statements

Table of Contents

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

(In Millions)

(Unaudited)



	Nine Months Ended September 30,
	2015			2014
Cash Flows from Operating Activities:
Net income (loss)	$	(183	)	$	435
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	724			784
Amortization of deferred financing costs	21			21
Deferred income taxes	(264		)	94
Unrealized loss (gain) on marketable securities	72			(73		)
Loss (gain) on indexed debt securities	(62		)	29
Write-down of natural gas inventory	4			2
Equity in (earnings) losses of unconsolidated affiliates, net of distributions	843			(6		)
Pension contributions	(63		)	(94		)
Changes in other assets and liabilities:
Accounts receivable and unbilled revenues, net	450			348
Inventory	33			(126		)
Taxes receivable	122			—
Accounts payable	(332		)	(237		)
Fuel cost recovery	71			(57		)
Non-trading derivatives, net	(7		)	(26		)
Margin deposits, net	20			(13		)
Interest and taxes accrued	(39		)	(59		)
Net regulatory assets and liabilities	92			53
Other current assets	22			23
Other current liabilities	(36		)	(20		)
Other assets	6			5
Other liabilities	9			29
Other, net	15			12
Net cash provided by operating activities	1,518			1,124

Cash Flows from Investing Activities:
Capital expenditures	(1,131		)	(998		)
Distributions from unconsolidated affiliates in excess of cumulative earnings	74			—
Decrease (increase) in restricted cash of transition and system restoration bond companies	9			(9		)
Proceeds from sale of marketable securities	32			—
Other, net	(8		)	(19		)
Net cash used in investing activities	(1,024		)	(1,026		)

Cash Flows from Financing Activities:
Increase (decrease) in short-term borrowings, net	(4		)	37
Proceeds of commercial paper, net	302			72
Proceeds from long-term debt	—			600
Payments of long-term debt	(513		)	(477		)
Debt issuance costs	—			(8		)
Payment of common stock dividends	(319		)	(306		)
Distribution to ZENS holders	(32		)	—
Other, net	1			6
Net cash used in financing activities	(565		)	(76		)

Net Increase (Decrease) in Cash and Cash Equivalents	(71		)	22
Cash and Cash Equivalents at Beginning of Period	298			208
Cash and Cash Equivalents at End of Period	$	227		$	230

Supplemental Disclosure of Cash Flow Information:
Cash Payments:
Interest, net of capitalized interest	$	323		$	338
Income tax payments, net	12			157
Non-cash transactions:
Accounts payable related to capital expenditures	87			63
Exercise of SESH put to Enable	1			196

See Notes to Interim Condensed Consolidated Financial Statements

Table of Contents

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(1) Background and Basis of Presentation

General. Included in this Quarterly Report on Form 10-Q (Form 10-Q) of CenterPoint Energy, Inc. are the condensed consolidated interim financial statements and notes (Interim Condensed Financial Statements) of CenterPoint Energy, Inc. and its subsidiaries (collectively, CenterPoint Energy). The Interim Condensed Financial Statements are unaudited, omit certain financial statement disclosures and should be read with the Annual Report on Form 10-K of CenterPoint Energy for the year ended December 31, 2014 (CenterPoint Energy 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 own interests in Enable Midstream Partners, LP (Enable) as described in Note 7. As of September 30, 2015, CenterPoint Energy’s indirect, wholly-owned subsidiaries included:


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

•

CenterPoint Energy Resources Corp. (CERC Corp. and, together with its subsidiaries, CERC), which owns and operates 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 gas utilities. As of September 30, 2015, CERC Corp. also owned approximately 55.4% of the limited partner interests in Enable, which owns, operates and develops natural gas and crude oil infrastructure assets.

As of September 30, 2015, CenterPoint Energy had variable interest entities (VIEs) consisting of transition and system restoration bond companies, which it consolidates. The consolidated VIEs are wholly-owned, bankruptcy-remote, special purpose entities that were formed specifically for the purpose of securitizing transition and system restoration-related property. Creditors of CenterPoint Energy have no recourse to any assets or revenues of the transition and system restoration bond companies. The bonds issued by these VIEs are payable only from and secured by transition and system restoration property, and the bondholders have no recourse to the general credit of CenterPoint Energy.

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

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

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

(2) New Accounting Pronouncements

In February 2015, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update No. 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis (ASU 2015-02). ASU 2015-02 changes the analysis that reporting organizations must perform to evaluate whether they should consolidate certain legal entities, such as limited partnerships. The changes include, among others, modification of the evaluation of whether limited partnerships and similar legal entities are variable interest entities (VIEs) or voting interest entities and elimination of the presumption that a general partner should consolidate a limited partnership. ASU 2015-02 does not amend the related party guidance for situations in which power is shared between two or more entities that hold interests in a VIE. ASU 2015-02 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2015. CenterPoint Energy will adopt ASU 2015-02 on January 1, 2016 and is currently assessing the impact, if any, that this standard will have on its financial position, results of operations, cash flows and disclosures.

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In April 2015, the FASB issued Accounting Standards Update No. 2015-03, Interest-Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Cost (ASU 2015-03). ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by ASU 2015-03. CenterPoint Energy will adopt ASU 2015-03 retrospectively on January 1, 2016, which will result in a reduction of both other long-term assets and long-term debt on its Condensed Consolidated Balance Sheets. CenterPoint Energy had debt issuance costs of $55 million and $61 million included in other long-term assets on its Condensed Consolidated Balance Sheets as of September 30, 2015 and December 31, 2014, respectively.

In April 2015, the FASB issued Accounting Standards Update No. 2015-05, Intangibles-Goodwill and Other-Internal-Use Software (Subtopic 350-40) (ASU 2015-05). ASU 2015-05 provides guidance to customers about whether a cloud computing arrangement includes a software license. If a cloud computing arrangement includes a software license, the customer should account for the software license element of the arrangement consistent with the acquisition of other software licenses. If a cloud computing arrangement does not include a software license, the customer should account for the arrangement as a service contract. The guidance will not change a customer’s accounting for service contracts. ASU 2015-05 is effective for fiscal years, and interim periods within the fiscal years, beginning after December 15, 2015 and may be adopted either prospectively or retrospectively. CenterPoint Energy will adopt ASU 2015-05 on January 1, 2016 and is currently assessing the impact that this standard will have on its financial position, results of operations, cash flows and disclosures.

In May 2014, the FASB issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (Topic 606) (ASU 2014-09), which supersedes most current revenue recognition guidance. ASU 2014-09 provides a comprehensive new revenue recognition model that requires revenue to be recognized in a manner that depicts the transfer of goods or services to a customer at an amount that reflects the consideration expected to be received in exchange for those goods or services. ASU 2014-09 was initially effective for fiscal years, and interim periods within those years, beginning after December 15, 2016. Early adoption is not permitted, and entities have the option of using either a full retrospective or a modified retrospective adoption approach. In August 2015, the FASB issued Accounting Standard Update No. 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date, which delays the effective date of ASU 2014-09 by one year. CenterPoint Energy is currently evaluating the impact that ASU 2014-09 will have on its financial position, results of operations, cash flows and disclosures, and may adopt ASU 2014-09 on January 1, 2018 as permitted by the new guidance.

In July 2015, the FASB issued Accounting Standards Update No. 2015-11, Inventory (Topic 330) Simplifying the Measurement of Inventory (ASU 2015-11). ASU 2015-11 changes the subsequent measurement guidance for inventory accounted for using methods other than the last in, first out (LIFO) and Retail Inventory methods. Companies will subsequently measure inventory at the lower of cost and net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. Subsequent measurement is unchanged for inventory measured using LIFO or the retail inventory method. ASU 2015-11 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, with early adoption permitted. CenterPoint Energy does not believe that ASU 2015-11 will have a material impact on its financial position, results of operations, cash flows and disclosures.

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) Employee Benefit Plans

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



	Three Months Ended September 30,
	2015						2014
	Pension Benefits (1)			Postretirement Benefits (1)			Pension Benefits (1)			Postretirement Benefits (1)
	(in millions)
Service cost	$	10		$	1		$	10		$	—
Interest cost	24			5			25			5
Expected return on plan assets	(30		)	(2		)	(32		)	(1		)
Amortization of prior service cost	2			—			3			—
Amortization of net loss	14			1			11			—
Amortization of transition obligation	—			—			—			1
Settlement cost (2)	1			—			—			—
Net periodic cost	$	21		$	5		$	17		$	5

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	Nine Months Ended September 30,
	2015						2014
	Pension Benefits (1)			Postretirement Benefits (1)			Pension Benefits (1)			Postretirement Benefits (1)
	(in millions)
Service cost	$	30		$	2		$	31		$	1
Interest cost	70			15			75			16
Expected return on plan assets	(90		)	(5		)	(94		)	(5		)
Amortization of prior service cost (credit)	7			(1		)	8			(1		)
Amortization of net loss	43			3			33			1
Amortization of transition obligation	—			—			—			4
Settlement cost (2)	10			—			—			—
Net periodic cost	$	70		$	14		$	53		$	16


(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 three and nine months ended September 30, 2015, CenterPoint Energy recognized a non-cash settlement charge of $1 million and $10 million, respectively. This charge is an acceleration of costs that would otherwise be recognized in future periods. CenterPoint Energy will continue to recognize incremental settlement costs in subsequent quarters as additional lump sum distributions are made under the non-qualified pension plan.

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
	Pension and Postretirement Plans						Pension and Postretirement Plans
	(in millions)
Beginning Balance	$	(81	)	$	(85	)	$	(85	)	$	(88	)
Amounts reclassified from accumulated other comprehensive loss:
Prior service cost (1)	1			1			1			2
Actuarial losses (1)	1			2			7			7
Total reclassifications from accumulated other comprehensive loss	2			3			8			9
Tax expense	(1		)	(1		)	(3		)	(4		)
Net current period other comprehensive income	1			2			5			5
Ending Balance	$	(80	)	$	(83	)	$	(80	)	$	(83	)


(1)	These components are included in the computation of net periodic cost.

CenterPoint Energy expects to contribute a total of approximately $66 million to its pension plans in 2015, of which approximately $38 million and $63 million were contributed during the three and nine months ended September 30, 2015, respectively.

CenterPoint Energy expects to contribute a total of approximately $17 million to its postretirement benefits plan in 2015, of which approximately $4 million and $12 million were contributed during the three and nine months ended September 30, 2015, respectively.

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(4) Regulatory Accounting

As of September 30, 2015, CenterPoint Energy has not recognized an allowed equity return of $405 million because such return will be recognized as it is recovered in rates. During the three months ended September 30, 2015 and 2014, CenterPoint Houston recognized approximately $16 million and $20 million, respectively, of the allowed equity return not previously recognized. During the nine months ended September 30, 2015 and 2014, CenterPoint Houston recognized approximately $37 million and $52 million, respectively, of the allowed equity return not previously recognized.

(5) 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.

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 its natural gas distribution business (NGD) in Arkansas, Louisiana, Mississippi, Minnesota and Oklahoma. NGD in Texas and electric operations in Texas do not have such mechanisms. As a result, fluctuations from normal weather may have a positive or negative effect on NGD’s results in Texas and on CenterPoint Houston’s results in its service territory.

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 both 2013–2014 and 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 CenterPoint Houston service territory, which contained a bilateral dollar cap of $8 million for both the 2013–2014 and 2014–2015 winter seasons and a bilateral dollar cap of $7 million for the 2015–2016 winter season. The swaps are based on ten-year normal weather. During both the three months ended September 30, 2015 and 2014, CenterPoint Energy recognized no losses related to these swaps. During the nine months ended September 30, 2015 and 2014, CenterPoint Energy recognized losses of $9 million and $8 million, respectively, related to these swaps. Weather hedge gains and losses are included in revenues in the Condensed Statements of Consolidated 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 September 30, 2015 and December 31, 2014, while the last two tables provide a breakdown of the related income statement impacts for the three and nine months ended September 30, 2015 and 2014.



Fair Value of Derivative Instruments
		September 30, 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)	Current Assets: Non-trading derivative assets	$	80	$	2
Natural gas derivatives (1) (2)	Other Assets: Non-trading derivative assets	39		—
Natural gas derivatives (1) (2)	Current Liabilities: Non-trading derivative liabilities	16		59
Natural gas derivatives (1) (2)	Other Liabilities: Non-trading derivative liabilities	3		24
Indexed debt securities derivative	Current Liabilities	—		454
Total		$	138	$	539


(1)	The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling 776 billion cubic feet (Bcf) or a net 77 Bcf long position. Of the net long position, basis swaps constitute 128 Bcf.

(2)

Natural gas contracts are presented on a net basis in the Condensed Consolidated Balance Sheets. Natural gas contracts are subject to master netting arrangements. This netting applies to all undisputed amounts due or past due and causes derivative assets (liabilities) to be ultimately presented net in a liability (asset) account within the Condensed Consolidated Balance Sheets. The net of total non-trading derivative assets and liabilities was a $100 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 $47 million.



Offsetting of Natural Gas Derivative Assets and Liabilities
	September 30, 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	$	96		$	(18	)	$	78
Other Assets: Non-trading derivative assets	42			(3		)	39
Current Liabilities: Non-trading derivative liabilities	(61		)	49			(12		)
Other Liabilities: Non-trading derivative liabilities	(24		)	19			(5		)
Total	$	53		$	47		$	100


(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, 2014
Total derivatives not designated as hedging instruments	Balance Sheet Location	Derivative Assets Fair Value		Derivative Liabilities Fair Value
		(in millions)
Natural gas derivatives (1) (2)	Current Assets: Non-trading derivative assets	$	101	$	1
Natural gas derivatives (1) (2)	Other Assets: Non-trading derivative assets	32		—
Natural gas derivatives (1) (2)	Current Liabilities: Non-trading derivative liabilities	14		83
Natural gas derivatives (1) (2)	Other Liabilities: Non-trading derivative liabilities	2		18
Indexed debt securities derivative	Current Liabilities	—		541
Total		$	149	$	643


(1)	The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling 804 Bcf or a net 60 Bcf long position. Of the net long position, basis swaps constitute 127 Bcf.

(2)

Natural gas contracts are presented on a net basis in the Condensed Consolidated Balance Sheets. Natural gas contracts are subject to master netting arrangements. This netting applies to all undisputed amounts due or past due and causes derivative assets (liabilities) to be ultimately presented net in a liability (asset) account within the Condensed Consolidated Balance Sheets. The net of total non-trading derivative assets and liabilities was a $111 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 $64 million.



Offsetting of Natural Gas Derivative Assets and Liabilities
	December 31, 2014
	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	$	115		$	(16	)	$	99
Other Assets: Non-trading derivative assets	34			(2		)	32
Current Liabilities: Non-trading derivative liabilities	(84		)	65			(19		)
Other Liabilities: Non-trading derivative liabilities	(18		)	17			(1		)
Total	$	47		$	64		$	111


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


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

Realized and unrealized gains and losses on 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.

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Income Statement Impact of Derivative Activity
		Three Months Ended September 30,
Total derivatives not designated as hedging instruments	Income Statement Location	2015			2014
		(in millions)
Natural gas derivatives	Gains (Losses) in Revenues	$	39		$	22
Natural gas derivatives (1)	Gains (Losses) in Expenses: Natural Gas	(30		)	(4		)
Indexed debt securities derivative	Gains (Losses) in Other Income (Expense)	129			(22		)
Total		$	138		$	(4	)


(1)	The Gains (Losses) in Expenses: Natural Gas includes $-0- during each of the three months ended September 30, 2015 and 2014 related to physical forwards purchased from Enable.



Income Statement Impact of Derivative Activity
		Nine Months Ended September 30,
Total derivatives not designated as hedging instruments	Income Statement Location	2015			2014
		(in millions)
Natural gas derivatives	Gains (Losses) in Revenues	$	88		$	(74	)
Natural gas derivatives (1)	Gains (Losses) in Expenses: Natural Gas	(72		)	110
Indexed debt securities derivative	Gains (Losses) in Other Income (Expense)	62			(29		)
Total		$	78		$	7


(1)	The Gains (Losses) in Expenses: Natural Gas includes $-0- and $2 million during the nine months ended September 30, 2015 and 2014, respectively, related to physical forwards purchased from Enable.


(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 Standard & Poor’s Ratings Services or Moody’s Investors Service, Inc. 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 at September 30, 2015 and December 31, 2014 was $3 million and $2 million, respectively. CenterPoint Energy posted no assets as collateral towards derivative instruments that contain credit risk contingent features at either September 30, 2015 or December 31, 2014. If all derivative contracts (in a net liability position) containing credit risk contingent features were triggered at September 30, 2015 and December 31, 2014, $3 million and $2 million, respectively, of additional assets would be required to be posted as collateral.

(6) 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

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Energy’s Level 3 assets or liabilities. At September 30, 2015, 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 $1.17 to $3.78 per one million British thermal units) as an unobservable input. Level 3 options are valued through Black-Scholes (including forward start) option models which include option volatilities (ranging from 0% to 76%) 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 nine months ended September 30, 2015, there were no transfers between Level 1 and 2. CenterPoint Energy also recognizes purchases of Level 3 financial assets and liabilities at their fair market value at the end of the reporting period.

The following tables present information about CenterPoint Energy’s assets and liabilities (including derivatives that are presented net) measured at fair value on a recurring basis as of September 30, 2015 and December 31, 2014, 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 September 30, 2015
			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Netting Adjustments (1)			Balance as of September 30, 2015
	(in millions)
Assets
Corporate equities	$	828	$	—	$	—	$	—		$	828
Investments, including money market funds (2)	55		—		—		—			55
Natural gas derivatives	5		111		22		(21		)	117
Total assets	$	888	$	111	$	22	$	(21	)	$	1,000
Liabilities
Indexed debt securities derivative	$	—	$	454	$	—	$	—		$	454
Natural gas derivatives	14		63		8		(68		)	17
Total liabilities	$	14	$	517	$	8	$	(68	)	$	471


(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 $47 million posted with the same counterparties.


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

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	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Netting Adjustments (1)			Balance as of December 31, 2014
			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Netting Adjustments (1)			Balance as of December 31, 2014
	(in millions)
Assets
Corporate equities	$	932	$	—	$	—	$	—		$	932
Investments, including money market funds (2)	54		—		—		—			54
Natural gas derivatives	7		122		20		(18		)	131
Total assets	$	993	$	122	$	20	$	(18	)	$	1,117
Liabilities
Indexed debt securities derivative	$	—	$	541	$	—	$	—		$	541
Natural gas derivatives	22		77		3		(82		)	20
Total liabilities	$	22	$	618	$	3	$	(82	)	$	561


(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 $64 million posted with the same counterparties.


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

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



	Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Derivative assets and liabilities, net
	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
	(in millions)
Beginning balance	$	10		$	4		$	17		$	3
Total gains	5			6			5			6
Total settlements	(2		)	(1		)	(8		)	1
Transfers into Level 3	1			—			1			(1		)
Transfers out of Level 3	—			—			(1		)	—
Ending balance (1)	$	14		$	9		$	14		$	9
The amount of total gains for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the reporting date	$	6		$	6		$	7		$	7


(1)	CenterPoint Energy did not have significant Level 3 purchases or sales during either of the three or nine months ended September 30, 2015 or 2014.

Items Measured at Fair Value on a Nonrecurring Basis

Based on the sustained low Enable common unit price and further declines in such price during the three months ended September 30, 2015 as well as the market outlook for continued depressed crude oil and natural gas prices impacting the midstream oil and gas industry, CenterPoint Energy determined in connection with its preparation of financial statements for the three months ended September 30, 2015, that an other than temporary decrease in the value of its investment in Enable had occurred. The impairment analysis compared the estimated fair value of CenterPoint Energy’s investment in Enable to its carrying value. The fair value of the investment was determined using multiple valuation methodologies under both the market and income approaches.

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Both of these approaches incorporate significant estimates and assumptions, including:

Market Approach


•	quoted price of Enable’s common units;


•	recent market transactions of comparable companies; and


•	EBITDA to total enterprise multiples for comparable companies.

Income Approach


•	Enable’s forecasted cash distributions;


•	projected cash flows of incentive distribution rights;


•	forecasted growth rate of Enable’s cash distributions; and


•	determination of the cost of equity, including market risk premiums.

Weighting of the different approaches

Significant unobservable inputs used include the growth rate applied to the projected cash distributions beyond 2020 and the discount rate used to determine the present value of the estimated future cash flows. Based on the significant unobservable estimates and assumptions required, CenterPoint Energy concluded that the fair value estimate should be classified as a Level 3 measurement within the fair value hierarchy. As a result of the analysis, CenterPoint Energy recorded an other than temporary impairment on its investment in Enable of $250 million, reducing the fair value of the investment to $3.6 billion. See Note 7 for further discussion of the impairment. As of December 31, 2014, there were no significant assets or liabilities measured at fair value on a nonrecurring basis.

Estimated Fair Value of Financial Instruments

The fair values of cash and cash equivalents, investments in debt and equity securities classified as “trading” and short-term borrowings are estimated to be approximately equivalent to carrying amounts and have been excluded from the table below. The carrying amounts of non-trading derivative assets and liabilities and CenterPoint Energy’s 2.0% Zero-Premium Exchangeable Subordinated Notes due 2029 (ZENS) 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.



	September 30, 2015				December 31, 2014
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)
Financial assets:
Notes receivable - affiliated companies	$	363	$	362	$	363	$	362
Financial liabilities:
Long-term debt	$	8,448	$	9,047	$	8,652	$	9,427

(7) Unconsolidated Affiliates

On May 1, 2013 (the Closing Date) CERC Corp., OGE Energy Corp. (OGE) and ArcLight Capital Partners, LLC 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 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 as presented in the Condensed Consolidated Balance Sheet at September 30, 2015, CERC Corp.’s guarantee of collection of Enable’s $1.1 billion senior notes due 2019 and 2024 (Guaranteed Senior Notes) and other guarantees discussed in Note 13, CERC Corp.’s $363 million notes receivable from Enable and outstanding current accounts receivable from Enable. The $363 million of notes receivable from Enable bears interest at an annual rate of 2.10% to 2.45% and

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matures in 2017. CenterPoint Energy recorded interest income of $2 million during each of the three months ended September 30, 2015 and 2014, and $6 million during each of the nine months ended September 30, 2015 and 2014, and had interest receivable from Enable of $2 million and $4 million as of September 30, 2015 and December 31, 2014, respectively, on its notes receivable.

Effective on the Closing Date, CenterPoint Energy and Enable entered into a Services Agreement, Employee Transition Agreement, Transitional Seconding Agreement, and other agreements (Transition Agreements). Under the Services Agreement, CenterPoint Energy agreed to provide certain support services to Enable such as accounting, legal, risk management and treasury functions for an initial term. The initial term of the Services Agreement ends on April 30, 2016, after which date such services continue on a year-to-year basis unless terminated by Enable with at least 90 days’ notice. Enable may terminate the Services Agreement, or the provision of any services thereunder, upon approval by its board of directors and at least 180 days’ notice.

CenterPoint Energy provided seconded employees to Enable to support its operations for a term ending on December 31, 2014. Enable, at its discretion, had the right to select and offer employment to seconded employees from CenterPoint Energy. During the fourth quarter of 2014, Enable notified CenterPoint Energy that it provided employment offers to substantially all of the seconded employees from CenterPoint Energy. Substantially all of the seconded employees became employees of Enable effective January 1, 2015.

In accordance with the Enable formation agreements, CenterPoint Energy had certain put rights, and Enable had certain call rights, exercisable with respect to the 25.05% interest in Southeast Supply Header, LLC (SESH) retained by CenterPoint Energy on the Closing Date, under which CenterPoint Energy would contribute its retained interest in SESH, in exchange for a specified number of limited partner common units in Enable and a cash payment, payable either from CenterPoint Energy to Enable or from Enable to CenterPoint Energy, to the extent of changes in the value of SESH subject to certain restrictions. Specifically, the rights were exercisable with respect to (1) a 24.95% interest in SESH, which closed on May 30, 2014 and (2) a 0.1% interest in SESH, which closed on June 30, 2015.

CenterPoint Energy billed Enable for reimbursement of transition services, including the costs of seconded employees, $3 million and $36 million during the three months ended September 30, 2015 and 2014, respectively, and $10 million and $118 million during the nine months ended September 30, 2015 and 2014, respectively, under the Transition Agreements. Actual transition services costs are recorded net of reimbursements received from Enable. CenterPoint Energy had accounts receivable from Enable of $4 million and $28 million as of September 30, 2015 and December 31, 2014, respectively, for amounts billed for transition services, including the cost of seconded employees.

CenterPoint Energy incurred natural gas expenses, including transportation and storage costs, of $23 million and $24 million during the three months ended September 30, 2015 and 2014, respectively, and $87 million and $99 million during the nine months ended September 30, 2015 and 2014, respectively, for transactions with Enable. CenterPoint Energy had accounts payable to Enable of $8 million and $23 million at September 30, 2015 and December 31, 2014, respectively, from such transactions.

As of September 30, 2015, 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 September 30, 2015, 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.

CenterPoint Energy recognized a loss of $794 million from its investment in Enable for the three months ended September 30, 2015. This loss included impairment charges totaling $862 million composed of CenterPoint Energy’s impairment of its investment in Enable of $250 million and CenterPoint Energy’s share, $612 million, of impairment charges Enable recorded for goodwill and long-lived assets.

CenterPoint Energy evaluates its equity method investments for impairment when factors indicate that a decrease in the value of its investment has occurred and the carrying amount of its investment may not be recoverable. An impairment loss, based on the excess of the carrying value over estimated fair value of the investment, is recognized in earnings when an impairment is deemed to be other than temporary. Considerable judgment is used in determining if an impairment loss is other than temporary and the amount of any impairment. Based on the sustained low Enable common unit price and further declines in such price during the three months ended September 30, 2015 as well as the market outlook for continued depressed crude oil and natural gas prices impacting the midstream oil and gas industry, CenterPoint Energy determined in connection with its preparation of financial statements for the three months ended September 30, 2015, that an other than temporary decrease in the value of its investment in Enable had occurred. CenterPoint Energy wrote down the value of its investment in Enable to its estimated fair value of $3.6 billion which resulted in an impairment charge of $250 million as of September 30, 2015. Both the income approach and market approach were utilized to estimate the fair value of CenterPoint Energy’s total investment in Enable, which includes the limited partner common and subordinated units, general partner interest and incentive distribution rights held by CenterPoint Energy. The determination of fair value considered a number of relevant factors including Enable’s common unit price and forecasted results,

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recent comparable transactions and the limited float of Enable’s publicly traded common units. See Note 6 for further discussion of the determination of fair value of CenterPoint Energy’s investment in Enable.

Investment in Unconsolidated Affiliates:



	September 30, 2015		December 31, 2014
	(in millions)
Enable	$	3,604	$	4,520
SESH (1)	—		1
Total	$	3,604	$	4,521


(1)	CenterPoint Energy disposed of its remaining interest in SESH on June 30, 2015.

Equity in Earnings (Losses) of Unconsolidated Affiliates, net:



	Three Months Ended September 30,					Nine Months Ended September 30,
	2015			2014		2015			2014
	(in millions)
Enable	$	(794	)	$	79	$	(699	)	$	236
SESH (1)	—			—		—			5
Total	$	(794	)	$	79	$	(699	)	$	241


(1)	CenterPoint Energy disposed of its remaining interest in SESH on June 30, 2015.

Summarized unaudited consolidated income information for Enable is as follows:



	Three Months Ended September 30,					Nine Months Ended September 30,
	2015			2014		2015			2014
	(in millions)
Operating revenues	$	646		$	804	$	1,852		$	2,632
Cost of sales, excluding depreciation and amortization	287			439		856			1,550
Impairment of goodwill and other long-lived assets	1,105			1		1,105			1
Operating income (loss)	(975		)	151		(778		)	452
Net income (loss) attributable to Enable	(985		)	139		(817		)	408

Reconciliation of Equity in Earnings (Losses), net:
CenterPoint Energy’s interest	$	(546	)	$	76	$	(453	)	$	230
Basis difference accretion	2			3		4			6
Impairment of CenterPoint Energy’s equity method investment in Enable	(250		)	—		(250		)	—
CenterPoint Energy’s equity in earnings (losses), net (1)	$	(794	)	$	79	$	(699	)	$	236

(1)

These amounts include CenterPoint Energy’s share of Enable’s impairment of goodwill and long-lived assets and the impairment of CenterPoint Energy’s equity method investment in Enable totaling $862 million during the three and nine months ended September 30, 2015. This impairment is offset by $68 million and $163 million of earnings for the three and nine months ended September 30, 2015, respectively.

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



	September 30, 2015			December 31, 2014
	(in millions)
Current assets	$	427		$	438
Non-current assets	10,774			11,399
Current liabilities	804			671
Non-current liabilities	2,786			2,343
Non-controlling interest	25			31
Enable partners’ capital	7,586			8,792

Reconciliation of Investment in Enable:
CenterPoint Energy’s ownership interest in Enable partners’ capital	$	4,200		$	4,869
CenterPoint Energy’s existing basis difference	(346		)	(349		)
Impairment of CenterPoint Energy’s equity method investment in Enable	(250		)	—
CenterPoint Energy’s investment in Enable	$	3,604		$	4,520

Distributions Received from Unconsolidated Affiliates:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
	(in millions)
Enable	$	74	$	70	$	219	$	227
SESH (1)	—		1		—		8
Total	$	74	$	71	$	219	$	235


(1)	CenterPoint Energy disposed of its remaining interest in SESH on June 30, 2015.

(8) Goodwill

Goodwill by reportable business segment as of both September 30, 2015 and December 31, 2014 is as follows:



	(in millions)
Natural Gas Distribution	$	746
Energy Services	83
Other Operations	11
Total	$	840

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

CenterPoint Energy performed its annual goodwill impairment test in the third quarter of 2015 and determined, based on the results of the first step, that no goodwill impairment charge was required for any reportable segment.

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(9) 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. At September 30, 2015, 430,262,314 shares of CenterPoint Energy, Inc. common stock were issued and 430,262,148 shares were outstanding. At December 31, 2014, 429,795,996 shares of CenterPoint Energy, Inc. common stock were issued and 429,795,830 shares were outstanding. Outstanding common shares exclude 166 treasury shares at both September 30, 2015 and December 31, 2014.

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

In September 1999, CenterPoint Energy issued ZENS having an original principal amount of $1.0 billion, of which $828 million remains outstanding at September 30, 2015. Each ZENS note was originally exchangeable at the holder’s option at any time for an amount of cash equal to 95% of the market value of the reference shares of Time Warner Inc. common stock (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. The principal amount of ZENS increases or decreases to the extent the annual yield from interest and cash dividends on the reference shares is less than or more than 2.309%. The adjusted principal amount is defined in the ZENS instrument as “contingent principal.” Prior to the closing of the merger discussed below, the reference shares for each ZENS note consisted of 0.5 share of TW Common, 0.125505 share of Time Warner Cable Inc. (TWC) common stock (TWC Common), 0.045455 share of AOL Inc. common stock (AOL Common) and 0.0625 share of Time Inc. common stock (Time Common).

On May 26, 2015, Verizon Communications, Inc. (Verizon) initiated a tender offer to purchase all outstanding shares of AOL Common for $50 per share, in which CenterPoint Energy tendered all of its shares of AOL Common for $32 million. Verizon acquired the remaining eligible shares through a merger, which closed on June 23, 2015. In accordance with the terms of the ZENS, CenterPoint Energy remitted $32 million to ZENS holders in July 2015, which reduced contingent principal. As a result, CenterPoint Energy recorded a reduction in the indexed debt securities derivative liability of $18 million, a reduction in the indexed debt balance of $7 million and a loss of $7 million, which is included in Gain (loss) on indexed debt securities on the Condensed Statements of Consolidated Income. As of September 30, 2015, the reference shares for each ZENS note consisted of 0.5 share of TW Common, 0.125505 share of TWC Common and 0.0625 share of Time Common and the contingent principal balance was $708 million.

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

(11) 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 2018. 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 they had an associated principal obligation of $49 million and $53 million as of September 30, 2015 and December 31, 2014, respectively.


(b)	Long-term Debt

Debt Repayments. In June 2015, CenterPoint Energy repaid its $200 million 6.85% Senior Notes using proceeds from its commercial paper program. CenterPoint Energy’s $1.2 billion revolving credit facility backstops its $1.0 billion commercial paper program.

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Credit Facilities. As of September 30, 2015 and December 31, 2014, CenterPoint Energy, CenterPoint Houston and CERC Corp. had the following revolving credit facilities and utilization of such facilities:



			September 30, 2015						December 31, 2014
	Size of Facility		Loans		Letters of Credit		Commercial Paper		Loans		Letters of Credit		Commercial Paper
	(in millions)
CenterPoint Energy	$	1,200	$	—	$	6	$	725	$	—	$	6	$	191
CenterPoint Houston	300		—		4		—		—		4		—
CERC Corp.	600		—		2		109		—		—		341
Total	$	2,100	$	—	$	12	$	834	$	—	$	10	$	532

CenterPoint Energy’s $1.2 billion revolving credit facility, which is scheduled to terminate on September 9, 2019, can be drawn at the London Interbank Offered Rate (LIBOR) plus 1.25% based on CenterPoint Energy’s current credit ratings. The revolving credit facility contains a financial covenant which limits CenterPoint Energy’s consolidated debt (excluding transition and system restoration bonds) to an amount not to exceed 65% of CenterPoint Energy’s consolidated capitalization. The financial covenant limit will temporarily increase from 65% to 70% if CenterPoint Houston experiences damage from a natural disaster in its service territory and CenterPoint Energy certifies to the administrative agent that CenterPoint Houston has incurred system restoration costs reasonably likely to exceed $100 million in a consecutive twelve-month period, all or part of which CenterPoint Houston intends to seek to recover through securitization financing. Such temporary increase in the financial covenant would be in effect from the date CenterPoint Energy delivers its certification until the earliest to occur of (i) the completion of the securitization financing, (ii) the first anniversary of CenterPoint Energy’s certification or (iii) the revocation of such certification.

CenterPoint Houston’s $300 million revolving credit facility, which is scheduled to terminate on September 9, 2019, can be drawn at LIBOR plus 1.125% based on CenterPoint Houston’s current credit ratings. The revolving credit facility contains a financial covenant which limits CenterPoint Houston’s consolidated debt (excluding transition and system restoration bonds) to an amount not to exceed 65% of CenterPoint Houston’s consolidated capitalization.

CERC Corp.’s $600 million revolving credit facility, which is scheduled to terminate on September 9, 2019, can be drawn at LIBOR plus 1.50% based on CERC Corp.’s current credit ratings. The revolving credit facility contains a financial covenant which limits CERC’s consolidated debt to an amount not to exceed 65% of CERC’s consolidated capitalization.

CenterPoint Energy, CenterPoint Houston and CERC Corp. were in compliance with all financial covenants as of September 30, 2015.

(12) Income Taxes

The effective tax rate reported for the three months ended September 30, 2015 was 38% compared to 33% for the same period in 2014. The effective tax rate reported for the nine months ended September 30, 2015 was 41% compared to 36% for the same period in 2014. The higher effective tax rate for the three and nine months ended September 30, 2015 was primarily due to lower earnings from the impairment of CenterPoint Energy’s investment in Enable. The impairment loss reduced the deferred tax liability on CenterPoint Energy’s investment in Enable.

CenterPoint Energy reported no uncertain tax liability as of September 30, 2015 and expects no significant change to the uncertain tax liability over the next twelve months. Tax years through 2013 have been audited and settled with the Internal Revenue Service (IRS). For 2014 and 2015, CenterPoint Energy is a participant in the IRS's Compliance Assurance Process.

(13) Commitments and Contingencies


(a)	Natural Gas Supply Commitments

Natural gas supply commitments include natural gas contracts related to CenterPoint Energy’s Natural Gas Distribution and Energy Services business segments, which have various quantity requirements and durations, that are not classified as non-trading derivative assets and liabilities in CenterPoint Energy’s Consolidated Balance Sheets as of September 30, 2015 and December 31, 2014 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 September 30, 2015, minimum payment obligations for natural gas supply commitments are approximately $159 million for the remaining three months in 2015, $489 million in 2016, $466 million in 2017, $413 million in 2018, $224 million in 2019 and $128 million after 2019.

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(b)	Legal, Environmental and Other Regulatory Matters

Legal Matters

Gas Market Manipulation Cases. CenterPoint Energy, CenterPoint Houston or their predecessor, Reliant Energy, Incorporated (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, Reliant Resources, Inc. (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 Energy, Inc. (GenOn). In December 2012, NRG acquired GenOn through a merger in which GenOn became a wholly-owned subsidiary of NRG. None of the sale of the retail business, the merger with Mirant Corporation, or the acquisition of GenOn by NRG alters RRI’s (now GenOn’s) contractual obligations to indemnify CenterPoint Energy and its subsidiaries, including CenterPoint Houston, for certain liabilities, including their indemnification obligations regarding the gas market manipulation litigation, nor does it affect the terms of existing guarantee arrangements for certain GenOn gas transportation contracts discussed below.

A large number of lawsuits were filed against numerous gas market participants in a number of federal and western state courts in connection with the operation of the natural gas markets in 2000–2002. CenterPoint Energy and its affiliates have since been released or dismissed from all but one such case. CenterPoint Energy Services, Inc. (CES), a subsidiary of CERC Corp., is a defendant in a case now pending in federal court in Nevada alleging a conspiracy to inflate Wisconsin natural gas prices in 2000–2002. In July 2011, the court issued an order dismissing the plaintiffs’ claims against other defendants in the case, each of whom had demonstrated Federal Energy Regulatory Commission jurisdictional sales for resale during the relevant period, based on federal preemption, and stayed the remainder of the case pending outcome of the appeals. The plaintiffs appealed this ruling to the U.S. Court of Appeals for the Ninth Circuit, which reversed the trial court’s dismissal of the plaintiffs’ claims. The U.S. Supreme Court agreed to review the case, and on April 21, 2015, affirmed the Ninth Circuit’s ruling and remanded the case to the district court for further proceedings. CenterPoint Energy and CES intend to continue vigorously defending against the plaintiffs’ claims on remand. 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 manufactured gas plants (MGPs) in the past. There are seven MGP sites in CERC’s Minnesota service territory. CERC believes it never owned or operated, and therefore has no liability with respect to, two of these sites. With respect to two other sites, CERC has completed state-ordered remediation, other than ongoing monitoring and water treatment.

At September 30, 2015, CERC had a recorded liability of $7 million for remediation of these five Minnesota sites. The estimated range of possible remediation costs for the sites for which CERC believes it may have responsibility was $4 million to $28 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 be dependent upon the number of sites to be remediated, the participation of other potentially responsible parties (PRPs), if any, and the remediation methods used.

In addition to the Minnesota sites, the U.S. Environmental Protection Agency and other regulators have investigated MGP sites that were owned or operated by CERC or that may have been owned by one of its former affiliates. CERC and CenterPoint Energy do not expect the ultimate outcome of these investigations 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 contain or have contained asbestos insulation and other asbestos-containing materials. CenterPoint Energy or its subsidiaries have been named, along with numerous others, as a defendant in lawsuits filed by a number of individuals who claim injury due to exposure to asbestos. Some of the claimants have worked at locations owned by subsidiaries of CenterPoint Energy, but most existing claims relate to facilities previously owned by CenterPoint Energy’s subsidiaries. In 2004 and early 2005, CenterPoint Energy sold its generating business, to which most of these claims relate, to a company which is now an affiliate of NRG. Under the terms of the arrangements regarding separation of the generating business from CenterPoint Energy and its sale of that business, ultimate financial responsibility for uninsured losses from claims relating to the generating business has been assumed by the NRG affiliate, but CenterPoint Energy has agreed to continue to defend such claims to the extent they are covered by insurance maintained by CenterPoint Energy, subject to reimbursement of the costs of such defense by the NRG affiliate. CenterPoint Energy anticipates that additional claims like those received may be asserted in the future. Although their ultimate outcome cannot be predicted at this time, CenterPoint Energy intends to continue vigorously

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contesting claims that it does not consider to have merit and, based on its experience to date, 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 on property where its subsidiaries conduct or 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, based on its experience to date, 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 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 transportation contracts, which will be in effect until 2018, was approximately $31 million as of September 30, 2015. Based on market conditions in the fourth quarter of 2015 at the time the most recent annual calculation was made under the agreement, GenOn was not obligated to post any security. If GenOn should fail to perform the contractual obligations, CERC could have to honor its guarantee and, in such event, any collateral then provided as security may be insufficient to satisfy CERC’s obligations.

CenterPoint Energy has provided guarantees (CenterPoint Midstream Guarantees) with respect to the performance of certain obligations of Enable under long-term gas gathering and treating agreements with an indirect, wholly-owned subsidiary of Encana Corporation (Encana) and an indirect, wholly-owned subsidiary of Royal Dutch Shell plc (Shell). Under the terms of the omnibus agreement entered into in connection with the closing of the formation of Enable, Enable and CenterPoint Energy have agreed to use commercially reasonable efforts and cooperate with each other to terminate the CenterPoint Midstream Guarantees and to release CenterPoint Energy from such guarantees by causing Enable or one of its subsidiaries to enter into substitute guarantees or to assume the CenterPoint Midstream Guarantees as applicable. The guarantee in favor of the indirect, wholly-owned subsidiary of Encana was released on August 24, 2015. As of September 30, 2015, CenterPoint Energy had guaranteed Enable’s obligations up to an aggregate amount of $50 million under the guarantee in favor of the indirect, wholly-owned subsidiary of Shell.

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

The fair value of these guarantees is not material.

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(14) Earnings Per Share

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



	Three Months Ended September 30,					Nine Months Ended September 30,
	2015			2014		2015			2014
	(in millions, except share and per share amounts)
Net income (loss)	$	(391	)	$	143	$	(183	)	$	435

Basic weighted average shares outstanding	430,262,000			429,796,000		430,152,000			429,580,000
Plus: Incremental shares from assumed conversions:
Restricted stock (1)	—			1,777,000		—			1,777,000
Diluted weighted average shares	430,262,000			431,573,000		430,152,000			431,357,000

Basic earnings (loss) per share
Net income (loss)	$	(0.91	)	$	0.33	$	(0.43	)	$	1.01

Diluted earnings (loss) per share
Net income (loss)	$	(0.91	)	$	0.33	$	(0.43	)	$	1.01


(1)	1,759,000 incremental shares from assumed conversions of restricted stock have not been included in the computation of diluted earnings (loss) per share for either the three months or nine months ended September 30, 2015, as their inclusion would be anti-dilutive.

(15) Reportable Business Segments

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

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 (CenterPoint Houston) 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.

Financial data for business segments is as follows:



	For the Three Months Ended September 30, 2015
	Revenues from External Customers			Net Intersegment Revenues			Operating Income
	(in millions)
Electric Transmission & Distribution	$	827	(1)	$	—		$	244
Natural Gas Distribution	353			6			11
Energy Services	446			6			7
Midstream Investments (2)	—			—			—
Other Operations	4			—			3
Eliminations	—			(12		)	—
Consolidated	$	1,630		$	—		$	265

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	For the Three Months Ended September 30, 2014
	Revenues from External Customers			Net Intersegment Revenues			Operating Income
	(in millions)
Electric Transmission & Distribution	$	839	(1)	$	—		$	232
Natural Gas Distribution	375			7			(8		)
Energy Services	589			15			6
Midstream Investments (2)	—			—			—
Other Operations	4			—			3
Eliminations	—			(22		)	—
Consolidated	$	1,807		$	—		$	233



	For the Nine Months Ended September 30, 2015
	Revenues from External Customers			Net Intersegment Revenues			Operating Income		Total Assets as of September 30, 2015
	(in millions)
Electric Transmission & Distribution	$	2,144	(1)	$	—		$	498	$	9,960
Natural Gas Distribution	1,958			21			176		5,360
Energy Services	1,482			28			29		852
Midstream Investments(2)	—			—			—		3,604
Other Operations	11			—			4		2,831			(3)
Eliminations	—			(49		)	—		(829		)
Consolidated	$	5,595		$	—		$	707	$	21,778



	For the Nine Months Ended September 30, 2014
	Revenues from External Customers			Net Intersegment Revenues			Operating Income		Total Assets as of December 31, 2014
	(in millions)
Electric Transmission & Distribution	$	2,166	(1)	$	—		$	482	$	10,066
Natural Gas Distribution	2,379			22			184		5,464
Energy Services	2,298			66			43		978
Midstream Investments (2)	—			—			—		4,521
Other Operations	11			—			5		3,368			(3)
Eliminations	—			(88		)	—		(1,197		)
Consolidated	$	6,854		$	—		$	714	$	23,200


(1)	CenterPoint Houston’s transmission and distribution revenues from major customers are as follows:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
	(in millions)
Affiliates of NRG	$	222	$	222	$	578	$	552
Affiliates of Energy Future Holdings Corp.	$	67	$	59	$	170	$	140


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



	Three Months Ended September 30,					Nine Months Ended September 30,
	2015			2014		2015			2014
	(in millions)
Enable (1)	$	(794	)	$	79	$	(699	)	$	236
SESH	—			—		—			5
Total	$	(794	)	$	79	$	(699	)	$	241

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(1)

Midstream Investments’ total assets are as follows:



	September 30, 2015		December 31, 2014
	(in millions)
Enable	$	3,604	$	4,520
SESH	—		1
Total	$	3,604	$	4,521


(3)	Included in total assets of Other Operations as of September 30, 2015 and December 31, 2014 are pension and other postemployment related regulatory assets of $741 million and $795 million, respectively.

(16) Subsequent Events

On October 21, 2015, CenterPoint Energy’s board of directors declared a regular quarterly cash dividend of $0.2475 per share of common stock payable on December 10, 2015, to shareholders of record as of the close of business on November 13, 2015.

On October 22, 2015, Enable declared a quarterly cash distribution of $0.318 per unit on all of its outstanding common and subordinated units for the quarter ended September 30, 2015. Accordingly, CERC Corp. expects to receive a cash distribution of approximately $74 million from Enable in the fourth quarter of 2015 to be made with respect to CERC Corp.’s limited partner interest in Enable for the third quarter of 2015.

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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 Annual Report on Form 10-K for the year ended December 31, 2014 (2014 Form 10-K).

RECENT EVENTS

Impairment of Equity Investment. We recognized a loss of $794 million from our investment in Enable for the three months ended September 30, 2015. This loss included impairment charges totaling $862 million composed of the impairment of our investment in Enable of $250 million and our share, $612 million, of impairment charges Enable recorded for goodwill and long-lived assets. For further discussion of the impairment, see Note 7.

Brazos Valley Connection Project. In April 2015, CenterPoint Houston Electric, LLC (CenterPoint Houston) filed a Certificate of Convenience and Necessity application with the Public Utility Commission of Texas (Texas Utility Commission) seeking approval to construct the Brazos Valley Connection (CenterPoint Houston’s portion of the Houston region transmission project). CenterPoint Houston has proposed 32 alternative routes for the project in the application, and the routing hearing was held on August 17 and 18, 2015. The hearing on the need for the line was held on September 2 and 3, 2015. On October 28, 2015, the administrative law judges (ALJs) issued a proposal for decision recommending that the Electric Reliability Council of Texas (ERCOT) studies of the project, along with the independent study commissioned by CenterPoint Houston, established the need for the project. In addition, the particular route selected by the ALJs results in a total cost of approximately $325 million.

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

On October 1, 2015, CenterPoint Houston filed an application with the Texas Utility Commission for an interim update of its TCOS seeking an increase in annual transmission revenues of $16.8 million based on an incremental increase of $107.6 million in total rate base. CenterPoint Houston expects to receive approval from the Texas Utility Commission in the fourth quarter of 2015.

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

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

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

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

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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 September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Revenues	$	1,630		$	1,807		$	5,595		$	6,854
Expenses	1,365			1,574			4,888			6,140
Operating Income	265			233			707			714
Interest and Other Finance Charges	(88		)	(88		)	(266		)	(261		)
Interest on Transition and System Restoration Bonds	(25		)	(30		)	(80		)	(90		)
Equity in Earnings (Losses) of Unconsolidated Affiliates, net	(794		)	79			(699		)	241
Other Income, net	7			19			26			72
Income (Loss) Before Income Taxes	(635		)	213			(312		)	676
Income Tax Expense (Benefit)	(244		)	70			(129		)	241
Net Income (Loss)	$	(391	)	$	143		$	(183	)	$	435

Basic Earnings (Loss) Per Share	$	(0.91	)	$	0.33		$	(0.43	)	$	1.01

Diluted Earnings (Loss) Per Share	$	(0.91	)	$	0.33		$	(0.43	)	$	1.01

Three months ended September 30, 2015 compared to three months ended September 30, 2014

We reported a consolidated net loss of $391 million ($(0.91) per diluted share) for the three months ended September 30, 2015 compared to net income of $143 million ($0.33 per diluted share) for the same period in 2014.

The decrease in net income of $534 million was due to the following key factors:


•	$873 million decrease in equity earnings of unconsolidated affiliates, which included impairment charges of $862 million, discussed further in Note 7; and

•$165 million increase in loss on our marketable securities included in Other Income, net shown above.

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

•$314 million decrease in income tax expense;

•$151 million increase in gain on our indexed debt securities included in Other Income, net shown above;

•$32 million increase in operating income (discussed below by segment);

•$5 million decrease in interest expense related to our transition and system restoration bonds; and

•$2 million increase in other income included in Other Income, net shown above.

Nine months ended September 30, 2015 compared to nine months ended September 30, 2014

We reported a consolidated net loss of $183 million ($(0.43) per diluted share) for the nine months ended September 30, 2015 compared to net income of $435 million ($1.01 per diluted share) for the same period in 2014.

The decrease in net income of $618 million was due to the following key factors:


•	$940 million decrease in equity earnings of unconsolidated affiliates, which included impairment charges of $862 million, discussed further in Note 7;

•$145 million increase in loss on our marketable securities included in Other Income, net shown above; and

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•$7 million decrease in operating income (discussed below by segment).

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

•$370 decrease in income tax expense;

•$91 increase in gain on our indexed debt securities included in Other Income, net shown above;

•$8 million increase in other income included in Other Income, net shown above; and

•$5 million decrease in net interest expense.

Income Tax Expense

Our effective tax rate reported for the three months ended September 30, 2015 was 38% compared to 33% for the same period in 2014. The effective tax rate reported for the nine months ended September 30, 2015 was 41% compared to 36% for the same period in 2014. The higher effective tax rate for the three and nine months ended September 30, 2015 was primarily due to lower earnings from the impairment of our investment in Enable. The impairment loss reduced the deferred tax liability on our investment in Enable. We expect our annual effective tax rate for 2015 to be approximately 45%.

RESULTS OF OPERATIONS BY BUSINESS SEGMENT

The following table presents operating income (loss) for each of our business segments for the three and nine months ended September 30, 2015 and 2014. Included in revenues are intersegment sales. We account for intersegment sales as if the sales were to third parties at current market prices.



	Three Months Ended September 30,					Nine Months Ended September 30,
	2015		2014			2015		2014
	(in millions)
Electric Transmission & Distribution	$	244	$	232		$	498	$	482
Natural Gas Distribution	11		(8		)	176		184
Energy Services	7		6			29		43
Other Operations	3		3			4		5
Total Consolidated Operating Income	$	265	$	233		$	707	$	714

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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 2014 Form 10-K.

The following table provides summary data of our Electric Transmission & Distribution business segment for the three and nine months ended September 30, 2015 and 2014:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
	(in millions, except throughput and customer data)
Revenues:
Electric transmission and distribution utility	$	683	$	660	$	1,782	$	1,716
Transition and system restoration bond companies	144		179		362		450
Total revenues	827		839		2,144		2,166
Expenses:
Operation and maintenance, excluding transition and system restoration bond companies	322		319		944		907
Depreciation and amortization, excluding transition and system restoration bond companies	86		83		253		247
Taxes other than income taxes	56		56		167		170
Transition and system restoration bond companies	119		149		282		360
Total expenses	583		607		1,646		1,684
Operating Income	$	244	$	232	$	498	$	482

Operating Income:
Electric transmission and distribution operations	$	219	$	202	$	418	$	392
Transition and system restoration bond companies (1)	25		30		80		90
Total segment operating income	$	244	$	232	$	498	$	482

Throughput (in gigawatt-hours (GWh)):
Residential	10,388		9,737		23,284		22,000
Total	25,612		24,802		65,378		63,129

Number of metered customers at end of period:
Residential	2,069,213		2,018,858		2,069,213		2,018,858
Total	2,337,806		2,284,202		2,337,806		2,284,202


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

Three months ended September 30, 2015 compared to three months ended September 30, 2014

Our Electric Transmission & Distribution business segment reported operating income of $244 million for the three months ended September 30, 2015, consisting of $219 million from the regulated electric transmission and distribution utility (TDU) and $25 million related to transition and system restoration bond companies (Bond Companies). For the three months ended September 30, 2014, operating income totaled $232 million, consisting of $202 million from TDU and $30 million related to Bond Companies.

TDU operating income increased $17 million due to the following key factors:

•higher usage of $11 million, primarily due to favorable weather;

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•	higher transmission-related revenues of $17 million, which were partially offset by increased transmission costs billed by transmission providers of $9 million;

•customer growth of $7 million; and


•	lower operation and maintenance expenses of $7 million.

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


•	one-time energy efficiency remand bonus in 2014 of $8 million; and


•	lower equity return of $7 million, primarily related to true-up proceeds.

Nine months ended September 30, 2015 compared to nine months ended September 30, 2014

Our Electric Transmission & Distribution business segment reported operating income of $498 million for the nine months ended September 30, 2015, consisting of $418 million from TDU and $80 million related to Bond Companies. For the nine months ended September 30, 2014, operating income totaled $482 million, consisting of $392 million from TDU and $90 million related to Bond Companies.

TDU operating income increased $26 million due to the following key factors:


•	higher transmission-related revenues of $61 million, which were partially offset by increased transmission costs billed by transmission providers of $38 million;

•customer growth of $18 million from the addition of over 53,000 new customers;

•higher usage of $17 million, primarily due to favorable weather; and


•	lower operation and maintenance expenses of $4 million.

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


•	lower equity return of $18 million, primarily related to true-up proceeds;


•	one-time energy efficiency remand bonus in 2014 of $8 million;


•	lower right of way revenues of $7 million; and


•	higher depreciation of $6 million.

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Natural Gas Distribution

For information regarding factors that may affect the future results of operations of our Natural Gas Distribution business segment, please read “Risk Factors — Risk Factors Associated with Our Consolidated Financial Condition,” “— Risk Factors Affecting Our Natural Gas Distribution and Energy Services Businesses” and “— Other Risk Factors Affecting Our Businesses or Our Interests in Enable Midstream Partners, LP” in Item 1A of Part I of our 2014 Form 10-K.

The following table provides summary data of our Natural Gas Distribution business segment for the three and nine months ended September 30, 2015 and 2014:



	Three Months Ended September 30,					Nine Months Ended September 30,
	2015		2014			2015		2014
	(in millions, except throughput and customer data)
Revenues	$	359	$	382		$	1,979	$	2,401
Expenses:
Natural gas	106		142			1,014		1,432
Operation and maintenance	155		169			510		524
Depreciation and amortization	55		52			165		149
Taxes other than income taxes	32		27			114		112
Total expenses	348		390			1,803		2,217
Operating Income (Loss)	$	11	$	(8	)	$	176	$	184

Throughput (in billion cubic feet (Bcf)):
Residential	12		12			128		140
Commercial and industrial	52		46			196		197
Total Throughput	64		58			324		337

Number of customers at end of period:
Residential	3,110,645		3,077,633			3,110,645		3,077,633
Commercial and industrial	248,911		246,789			248,911		246,789
Total	3,359,556		3,324,422			3,359,556		3,324,422

Three months ended September 30, 2015 compared to three months ended September 30, 2014

Our Natural Gas Distribution business segment reported operating income of $11 million for the three months ended September 30, 2015, compared to an operating loss of $8 million for the three months ended September 30, 2014.

Operating income increased $19 million as a result of the following key factors:


•	receipt of the Conservation Improvement Program Incentive (CIP) in August 2015, which has historically been received in the fourth quarter ($12 million);


•	increased rate relief ($5 million);


•	increased economic activity across our footprint, including customer growth ($3 million);


•	increased other revenues ($2 million); and


•	decreased operation and maintenance expense ($2 million).

These increases were partially offset by:


•	higher tax expense ($4 million); and


•	higher depreciation and amortization expense ($3 million).

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Increased expense related to gross receipt taxes ($1 million) was offset by the related revenue.

Nine months ended September 30, 2015 compared to nine months ended September 30, 2014

Our Natural Gas Distribution business segment reported operating income of $176 million for the nine months ended September 30, 2015, compared to $184 million for the nine months ended September 30, 2014.

Operating income decreased $8 million as a result of the following key factors:


•	decreased usage, primarily due to colder than normal weather in 2014 ($19 million);


•	higher depreciation and amortization expense ($17 million); and


•	higher tax expense ($7 million).

These decreases were partially offset by:


•	receipt of the CIP in August 2015, which has historically been received in the fourth quarter ($12 million);


•	increased rate relief ($11 million);


•	increased economic activity across our footprint, including the addition of approximately 35,000 customers ($7 million); and


•	increased other revenues ($5 million).

Decreased expense related to energy efficiency programs ($2 million) and decreased expense related to gross receipt taxes ($5 million) were offset by the related revenues.

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Energy Services

For information regarding factors that may affect the future results of operations of our Energy Services business segment, please read “Risk Factors — Risk Factors Associated with Our Consolidated Financial Condition,” “— Risk Factors Affecting Our Natural Gas Distribution and Energy Services Businesses” and “— Other Risk Factors Affecting Our Businesses or Our Interests in Enable Midstream Partners, LP” in Item 1A of Part I of our 2014 Form 10-K.

The following table provides summary data of our Energy Services business segment for the three and nine months ended September 30, 2015 and 2014:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
	(in millions, except throughput and customer data)
Revenues	$	452	$	604	$	1,510	$	2,364
Expenses:
Natural gas	433		582		1,445		2,280
Operation and maintenance	11		14		32		36
Depreciation and amortization	1		2		3		4
Taxes other than income taxes	—		—		1		1
Total expenses	445		598		1,481		2,321
Operating Income	$	7	$	6	$	29	$	43

Mark-to-market gain	$	5	$	13	$	3	$	23

Throughput (in Bcf)	138		140		459		463

Number of customers at end of period	18,052		17,900		18,052		17,900

Three months ended September 30, 2015 compared to three months ended September 30, 2014

Our Energy Services business segment reported operating income of $7 million for the three months ended September 30, 2015 compared to $6 million for the three months ended September 30, 2014. The increase in operating income of $1 million was primarily due to $4 million of improved margins and $3 million of decreased operation and maintenance expenses. Offsetting these increases was an $8 million decrease from mark-to-market accounting for derivatives associated with certain natural gas purchases and sales used to lock in economic margins. The third quarter of 2015 included a $5 million mark-to-market benefit compared to a $13 million mark-to-market benefit for the same period of 2014.

Nine months ended September 30, 2015 compared to nine months ended September 30, 2014

Our Energy Services business segment reported operating income of $29 million for the nine months ended September 30, 2015 compared to $43 million for the nine months ended September 30, 2014. The decrease in operating income of $14 million was primarily due to a $20 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 nine months of 2015 included a $3 million mark-to-market benefit compared to a $23 million mark-to-market benefit for the same period of 2014. Offsetting this decrease was a $4 million reduction in operation and maintenance expenses.

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Midstream Investments

For information regarding factors that may affect the future results of operations of our Midstream Investments business segment, please read “Risk Factors — Risk Factors Affecting Our Interests in Enable Midstream Partners, LP” and “— Other Risk Factors Affecting Our Businesses or Our Interests in Enable Midstream Partners, LP” in Item 1A of Part I of our 2014 Form 10-K.

The following table provides pre-tax equity income (loss) of our Midstream Investments business segment for the three and nine months ended September 30, 2015 and 2014:



	Three Months Ended September 30,					Nine Months Ended September 30,
	2015			2014		2015			2014
	(in millions)
Enable (1)	$	(794	)	$	79	$	(699	)	$	236
SESH	—			—		—			5
Total	$	(794	)	$	79	$	(699	)	$	241


(1)	These amounts include our share of Enable’s impairment of goodwill and long-lived assets and the impairment of our equity method investment in Enable totaling $862 million during the three and nine months ended September 30, 2015 (see Note 7). This impairment is offset by $68 million and $163 million of earnings for the three and nine months ended September 30, 2015, respectively.

Other Operations

The following table shows the operating income of our Other Operations business segment for the three and nine months ended September 30, 2015 and 2014:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
	(in millions)
Revenues	$	4	$	4	$	11	$	11
Expenses	1		1		7		6
Operating Income	$	3	$	3	$	4	$	5

CERTAIN FACTORS AFFECTING FUTURE EARNINGS

For information on other developments, factors and trends that may have an impact on our future earnings, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Certain Factors Affecting Future Earnings” in Item 7 of Part II of our 2014 Form 10-K, “Risk Factors” in Item 1A of Part I of our 2014 Form 10-K and “Cautionary Statement Regarding Forward-Looking Information” in this Form 10-Q.

LIQUIDITY AND CAPITAL RESOURCES

Historical Cash Flows

The following table summarizes the net cash provided by (used in) operating, investing and financing activities for the nine months ended September 30, 2015 and 2014:



	Nine Months Ended September 30,
	2015			2014
	(in millions)
Cash provided by (used in):
Operating activities	$	1,518		$	1,124
Investing activities	(1,024		)	(1,026		)
Financing activities	(565		)	(76		)

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Cash Provided by Operating Activities

Net cash provided by operating activities in the first nine months of 2015 increased $394 million compared to the same period in 2014 due primarily to increased cash related to a decrease in gas storage inventory ($149 million), decreased net tax payments ($145 million), increased cash provided by fuel cost recovery ($128 million), increased cash provided by net regulatory assets and liabilities ($39 million), decreased net margin deposits ($33 million) and decreased pension contributions ($31 million), which were partially offset by decreased distributions from unconsolidated affiliates ($90 million).

Cash Used in Investing Activities

Net cash used in investing activities in the first nine months of 2015 decreased $2 million compared to the same period in 2014 due primarily to a return of capital from unconsolidated affiliates ($74 million), increased proceeds from the sale of marketable securities ($32 million) and decreased restricted cash ($18 million), which were partially offset by increased capital expenditures ($133 million).

Cash Used in Financing Activities

Net cash used by financing activities in the first nine months of 2015 increased $489 million compared to the same period in 2014 due to decreased proceeds from long-term debt ($600 million), decreased short term borrowings ($41 million), increased payments of long-term debt ($36 million), increased distributions to ZENS holders ($32 million) and increased payment of common stock dividends ($13 million), which were partially offset by increased net proceeds from commercial paper ($230 million).

Future Sources and Uses of Cash

Our liquidity and capital requirements are affected primarily by our results of operations, capital expenditures, debt service requirements, tax payments, working capital needs and various regulatory actions. Our capital expenditures are expected to be used for investment in infrastructure for our electric transmission and distribution operations and our natural gas distribution operations. These capital expenditures are anticipated to maintain reliability and safety as well as expand our systems through value-added projects. Our principal anticipated cash requirements for the remaining three months of 2015 include the following:


•	capital expenditures of approximately $408 million;


•	scheduled principal payments on transition and system restoration bonds of $62 million;


•	maturing pollution control bonds aggregating $69 million, which were repaid using proceeds from our commercial paper program on October 1, 2015;


•	contributions aggregating approximately $3 million to qualified and non-qualified pension plans;


•	dividend payments on CenterPoint Energy common stock; and


•	interest payments on debt.

We expect that borrowings under our credit facilities, proceeds from commercial paper, anticipated cash flows from operations and distributions from Enable will be sufficient to meet our anticipated cash needs for the remaining three months of 2015. 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 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 Reliant Resources, Inc. (RRI) to our shareholders, CERC had guaranteed certain contractual obligations of what became RRI’s trading subsidiary. When the companies separated, RRI agreed to secure CERC against obligations under the guarantees RRI had been unable to extinguish by the time of separation. Pursuant to such agreement, as amended in December 2007, RRI (now GenOn Energy, Inc. (GenOn)) agreed to provide to CERC cash or letters of credit as security against CERC’s obligations under its remaining guarantees for demand charges under certain gas transportation agreements if and to the extent changes in market conditions expose CERC to a risk of loss on those guarantees based on an annual calculation, with any required collateral to be posted each December. The undiscounted maximum potential payout of the demand charges under these transportation contracts, which will be in effect until 2018, was approximately $31 million as of September 30, 2015. Based on market conditions in the fourth quarter of 2015 at the time the most recent annual calculation was made under

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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.

We have provided guarantees (CenterPoint Midstream Guarantees) with respect to the performance of certain obligations of Enable under long-term gas gathering and treating agreements with an indirect wholly-owned subsidiary of Encana Corporation (Encana) and an indirect wholly-owned subsidiary of Royal Dutch Shell plc (Shell). Under the terms of the omnibus agreement entered into in connection with the closing of the formation of Enable, we and Enable have agreed to use commercially reasonable efforts and cooperate with each other to terminate the CenterPoint Midstream Guarantees and to release us from such guarantees by causing Enable or one of its subsidiaries to enter into substitute guarantees or to assume the CenterPoint Midstream Guarantees as applicable. The guarantee in favor of the indirect, wholly-owned subsidiary of Encana was released on August 24, 2015. As of September 30, 2015, we have guaranteed Enable’s obligations up to an aggregate amount of $50 million under the guarantee in favor of the indirect, wholly-owned subsidiary of Shell.

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

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

Regulatory Matters

Significant regulatory developments that have occurred since our 2014 Form 10-K was filed with the Securities and Exchange Commission (SEC) are discussed below.

CenterPoint Houston

Brazos Valley Connection Project. In July 2013, CenterPoint Houston and other transmission service providers submitted analyses and transmission proposals to ERCOT for an additional transmission path into the Houston region. In April 2014, ERCOT’s Board of Directors voted to endorse a Houston region transmission project and deemed its completion before June 2018 critical for reliability. The project will consist of (i) construction of a new double-circuit 345 kilovolt (kV) line spanning approximately 130 miles, (ii) upgrades to three substations to accommodate new connections and additional capacity, and (iii) improvements to approximately 11 miles of an existing 345 kV TH Wharton-Addicks transmission line to increase its rating. Also in April 2014, ERCOT staff determined that CenterPoint Houston would be the designated transmission service provider for the portion of the project between our Zenith substation and the Gibbons Creek substation owned by the Texas Municipal Power Agency, consisting of approximately 60–78 miles (depending on the route approved by the Texas Utility Commission) of 345 kV transmission line, upgrades to the Limestone and Zenith substations and upgrades to 11 miles of the 345 kV TH Wharton-Addicks transmission line (this portion of the Houston region transmission project is referred to by CenterPoint Houston as the Brazos Valley Connection). Other transmission service providers were designated by ERCOT for the portion of the project from the Gibbons Creek Substation to the Limestone Substation as well as the upgrades to the Gibbons Creek Substation. In April 2015, CenterPoint Houston filed a Certificate of Convenience and Necessity application with the Texas Utility Commission seeking approval to construct the Brazos Valley Connection. CenterPoint Houston has proposed 32 alternative routes for the project in the application, and the routing hearing was held on August 17 and 18, 2015. The hearing on the need for the line was held on September 2 and 3, 2015. On October 28, 2015, the administrative law judges (ALJs) issued a proposal for decision recommending that the ERCOT studies of the project, along with the independent study commissioned by CenterPoint Houston, established the need for the project. In addition, the particular route selected by the ALJs results in a total cost of approximately $325 million. CenterPoint Houston anticipates a final decision from the Texas Utility Commission on both the need for, and the route of, the Brazos Valley Connection in the fourth quarter of 2015. Depending on the route selected by the Texas Utility Commission, CenterPoint Houston estimates that the capital costs for the Brazos Valley Connection will be approximately $276-$383 million. After approval of the application, CenterPoint Houston expects to complete construction of the Brazos Valley Connection by mid-2018.

In May 2014, several electric generators appealed the ERCOT Board of Directors’ April 2014 approval of the Houston region transmission project and the determination that the project was critical for reliability in the Houston region to the Texas Utility Commission. That appeal was denied by the Texas Utility Commission in December 2014. In March 2015, the electric generators petitioned the Texas District Court of Travis County for judicial review of the Texas Utility Commission’s denial of their appeal. That case is currently pending before that court.

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

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

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

The DCRF application must be filed between April 1 and April 8 of any given year. The application includes recovery of specific incremental distribution-related invested capital, including poles, transformers, conductors, meters and telecommunication equipment from the previous rate case to the end of the DCRF update period, less an adjustment for the related accumulated deferred income taxes. The application includes recovery of return on investment, depreciation expense, federal income tax, and other associated taxes less an adjustment for changes in customer count and weather normalized usage during the update period. The allocation to customer classes is conducted in the same manner as current rates. Any authorized rate change is applied to all retail customers on an energy or demand charge basis, effective September 1, 2015, through a separate DCRF charge. Only four DCRF changes may be implemented between rate cases. The utility must file an earnings monitoring report (EMR) annually with the DCRF application. By law, a DCRF application will be denied if the EMR shows the utility is earning more than its authorized rate of return using 10-year weather normalized data.

Energy Efficiency Cost Recovery Factor (EECRF). On June 1, 2015, CenterPoint Houston filed an application with the Texas Utility Commission for an adjustment to its EECRF to recover $37.7 million in 2016, including an incentive of $6.6 million based on 2014 program performance. In October 2015, the Texas Utility Commission approved the application. The effective date of the rate adjustment will be March 1, 2016.

CERC

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

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

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

Arkansas Energy Efficiency Cost Recovery (EECR). On March 31, 2015, NGD made an EECR filing with the Arkansas Public Service Commission (APSC) to recover $5.9 million for the 2015 program year. The purpose of the EECR is to recover NGD’s estimated expenses and lost contributions to fixed cost for the energy efficiency programs approved by the APSC and administered either jointly or individually by NGD, plus a utility incentive earned for 2014, with adjustments for any over- or under-recovery from the prior period. The impact to customer bills is expected to be a small reduction due to actual program costs being less than estimated and a colder than normal year causing more EECR revenues than anticipated. New rates went into effect in July 2015.

Arkansas Rate Case. On August 17, 2015, NGD filed a Notice of Intent to file a general rate case with the APSC. The rate case will be filed no later than November 15, 2015.

Louisiana Rate Stabilization Plan (RSP). NGD made its 2015 Louisiana RSP filings with the Louisiana Public Service Commission (LPSC) on October 1, 2015. The North Louisiana Rider RSP filing shows a revenue deficiency of $1.0 million, and the South Louisiana Rider RSP filing shows a revenue deficiency of $1.5 million. Both 2015 RSP filings utilized the capital structure and ROE factors approved by the LPSC on September 23, 2015 discussed below. NGD will begin billing in December 2015 subject to a refund. NGD made its 2014 Louisiana RSP filings with the LPSC on October 1, 2014. The North Louisiana Rider RSP filing shows a revenue deficiency of $4.0 million, compared to the authorized ROE of 10.25%. The South Louisiana Rider RSP filing shows a revenue deficiency of $2.3 million, compared to the authorized ROE of 10.5%. NGD began billing the revised rates in December 2014, subject to refund. On November 19, 2014, NGD sought permission to amend the 2013 South Louisiana RSP filing to use a more representative capital structure and to adjust the filing’s equity banding mechanism. On December 2, 2014, NGD sought permission for similar amendments to the 2013 North Louisiana RSP filing. On September 3, 2015, Uncontested Stipulated Settlement Agreements (Stipulations) between NGD and the LPSC Staff were filed in the 2013 Louisiana RSP dockets recommending a capital structure of 48% debt and 52% equity and ROE of 9.95%. On September 23, 2015, the LPSC issued orders approving the Stipulations and ordered refunds of the 2013 RSP over-collections plus 5% annual interest. Refunds for the 2013 North and South Louisiana RSP filings in the amount of approximately $0.9 million and $0.6 million, respectively, became effective in September 2015. The 2014 and 2015 Louisiana RSP filings are still awaiting final approval from the LPSC.

On February 20, 2015, the LPSC issued orders reducing rates and requiring refunds of over-collections plus 5% interest based on disallowance of certain costs included in the 2012 RSP filings. North Louisiana was required to adjust its 2012 RSP increase from $36,400 to $2,600. South Louisiana’s 2012 RSP was further reduced by $0.1 million. New rates went into effect on February 23, 2015.

Mississippi Rate Regulation Adjustment (RRA). On May 1, 2015, NGD filed for a $2.5 million RRA with an adjusted ROE of 9.534% with the Mississippi Public Service Commission (MPSC). Additional filings were made under the Supplemental Growth Rider (SGR) of approximately $0.1 million with an ROE of 12% and the EECR rider of approximately $0.6 million. The MPSC approved the EECR and new rates were implemented on September 2, 2015. New rates for the RRA and the SGR are expected to be implemented in the fourth quarter of 2015.

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

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

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Other Matters

Credit Facilities

As of October 23, 2015, we had the following facilities:



Execution Date	Company	Size of Facility		Amount Utilized at October 23, 2015 (1)			Termination Date
		(in millions)
September 9, 2011	CenterPoint Energy	$	1,200	$	764	(2)	September 9, 2019
September 9, 2011	CenterPoint Houston	300		4		(3)	September 9, 2019
September 9, 2011	CERC Corp.	600		14		(4)	September 9, 2019


(1)	Based on the consolidated debt to capitalization covenant in our revolving credit facility and the revolving credit facility of each of CenterPoint Houston and CERC Corp., we would have been permitted to utilize the full capacity of such revolving credit facilities, which aggregated $2.1 billion at September 30, 2015.


(2)	Represents outstanding commercial paper of $758 million and outstanding letters of credit of $6 million.


(3)	Represents outstanding letters of credit.


(4)	Represents outstanding commercial paper of $12 million and outstanding letters of credit of $2 million.

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

CenterPoint Houston’s $300 million revolving credit facility can be drawn at LIBOR plus 1.125% based on CenterPoint Houston’s current credit ratings. The revolving credit facility contains a financial covenant which limits CenterPoint Houston’s consolidated debt (excluding transition and system restoration bonds) to an amount not to exceed 65% of CenterPoint Houston’s consolidated capitalization.

CERC Corp.’s $600 million revolving credit facility can be drawn at LIBOR plus 1.5% based on CERC Corp.’s current credit ratings. The revolving credit facility contains a financial covenant which limits CERC’s consolidated debt to an amount not to exceed 65% of CERC’s consolidated capitalization.

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.

Our $1.2 billion revolving credit facility backstops our $1.0 billion commercial paper program. As of September 30, 2015, we had $725 million of outstanding commercial paper. In October 2015, we repaid our $69 million 4.9% pollution control bonds using proceeds from our commercial paper program. CERC Corp.’s $600 million revolving credit facility backstops its $600 million commercial paper program. As of September 30, 2015, CERC Corp. had $109 million of outstanding commercial paper.

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Securities Registered with the SEC

CenterPoint Energy, CenterPoint Houston and CERC Corp. have filed a joint shelf registration statement with the SEC registering indeterminate principal amounts of CenterPoint Houston’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 October 23, 2015, investments in money market funds by Bond Companies comprised substantially all of our temporary 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.

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 October 23, 2015, Moody’s Investors Service, Inc. (Moody’s), Standard & Poor’s Ratings Services (S&P), a division of The McGraw-Hill Companies, and Fitch, Inc. (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+

Stable

BBB

Stable

CenterPoint Houston Senior

Secured Debt

Stable

CERC Corp. Senior Unsecured

Debt

Baa2

Stable

A-

Stable

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

A decline in credit ratings could increase borrowing costs under our $1.2 billion revolving credit facility, CenterPoint Houston’s $300 million revolving credit facility and CERC Corp.’s $600 million revolving credit facility. If our credit ratings or those of CenterPoint Houston or CERC Corp. had been downgraded one notch by each of the three principal credit rating agencies from the ratings that existed at September 30, 2015, the impact on the borrowing costs under the three revolving credit facilities would have been immaterial in the three months ended September 30, 2015. 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

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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.

CenterPoint Energy Services, Inc. (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 gas utilities throughout the central and eastern United States. In order 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 September 30, 2015, the amount posted as collateral aggregated approximately $63 million. Should the credit ratings of CERC Corp. (as the credit support provider for CES) fall below certain levels, CES would be required to provide additional collateral up to the amount of its previously unsecured credit limit. We estimate that as of September 30, 2015, unsecured credit limits extended to CES by counterparties aggregated $308 million, and $3 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 $152 million as of September 30, 2015. The amount of collateral will depend on seasonal variations in transportation levels.

In September 1999, we issued ZENS having an original principal amount of $1.0 billion, of which $828 million remains outstanding at September 30, 2015. Each ZENS note was originally exchangeable at the holder’s option at any time for an amount of cash equal to 95% of the market value of the reference shares of TW Common attributable to such note. The number and identity of the reference shares attributable to each ZENS note are adjusted for certain corporate events. Prior to the closing of the merger discussed below, the reference shares for each ZENS note consisted of 0.5 share of TW Common, 0.125505 share of TWC Common, 0.045455 share of AOL Common and 0.0625 share of Time Common.

On May 26, 2015, Verizon initiated a tender offer to purchase all outstanding shares of AOL Common for $50 per share, in which we tendered all of our shares of AOL Common for $32 million. Verizon acquired the remaining eligible shares through a merger, which closed on June 23, 2015. In accordance with the terms of the ZENS, we remitted $32 million to ZENS holders in July, which reduced contingent principal. As a result, we recorded a reduction in the indexed debt securities derivative liability of $18 million, a reduction in the indexed debt balance of $7 million and a loss of $7 million. As of September 30, 2015, the reference shares for each ZENS note consisted of 0.5 share of TW Common, 0.125505 share of TWC Common and 0.0625 share of Time Common.

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, TWC Common and Time Common that we own or from other sources. We own shares of TW Common, TWC 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, TWC Common and Time Common shares would typically cease when ZENS notes are exchanged or otherwise retired and TW Common, TWC 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 September 30, 2015, deferred taxes of approximately $430 million would have been payable in 2015. If all the TW Common, TWC Common and Time Common had been sold on September 30, 2015, capital gains taxes of approximately $244 million would have been payable in 2015.

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 $75 million by us or any of

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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 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

Certain of the entities contributed to Enable by CERC Corp. are obligated on approximately $363 million of indebtedness owed to a wholly-owned subsidiary of CERC Corp. that is scheduled to mature in 2017.

Enable is expected to pay a minimum quarterly distribution of $0.2875 per unit on its outstanding units to the extent it has sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to its general partner and its affiliates (referred to as “available cash”) within 45 days after the end of each quarter. On October 22, 2015, Enable declared a quarterly cash distribution of $0.318 per unit on all of its outstanding common and subordinated units for the quarter ended September 30, 2015. Accordingly, CERC Corp. expects to receive a cash distribution of approximately $74 million from Enable in the fourth quarter of 2015 to be made with respect to CERC Corp.’s limited partner interest in Enable for the third quarter of 2015.

We recognized a loss of $794 million from our investment in Enable for the three months ended September 30, 2015. This loss included impairment charges totaling $862 million composed of the impairment of our investment in Enable of $250 million and our share, $612 million, of impairment charges Enable recorded for goodwill and long-lived assets. For further discussion of the impairment, see Note 7.

Dodd-Frank Swaps Regulation

We use derivative instruments such as physical forward contracts, swaps and options to mitigate the impact of changes in commodity prices and weather on our operating results and cash flows. Following enactment of the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank) in July 2010, the Commodity Futures Trading Commission (CFTC) has promulgated regulations to implement Dodd-Frank’s changes to the Commodity Exchange Act, including the definition of commodity-based swaps subject to those regulations. The CFTC regulations are intended to implement new reporting and record keeping requirements related to their swap transactions and a mandatory clearing and exchange-execution regime for various types, categories or classes of swaps, subject to certain exemptions, including the trade-option and end-user exemptions. Although we anticipate that most, if not all, of our swap transactions should qualify for an exemption to the clearing and exchange-execution requirements, we will still be subject to record keeping and reporting requirements. Other changes to the Commodity Exchange Act made as a result of Dodd-Frank and the CFTC’s implementing regulations could increase the cost of entering into new swaps.

Weather Hedge

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

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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;


•	the ability of retail electric providers (REPs), including REP affiliates of NRG Energy, Inc. 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;


•	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 2014 Form 10-K.

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

CenterPoint Houston’s revolving credit facility limits CenterPoint Houston’s consolidated debt (excluding transition and system restoration bonds) to an amount not to exceed 65% of its consolidated capitalization. CERC Corp.’s revolving credit facility limits CERC’s consolidated debt to an amount not to exceed 65% of its consolidated capitalization. Our revolving credit facility limits our consolidated debt (excluding transition and system restoration bonds) to an amount not to exceed 65% of our consolidated capitalization. The financial covenant limit in our revolving credit facility will temporarily increase from 65% to 70% if CenterPoint Houston experiences damage from a natural disaster in its service territory that meets certain criteria. Additionally, CenterPoint Houston 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.

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Item 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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. At September 30, 2015, the recorded fair value of our non-trading energy derivatives was a net asset of $53 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 September 30, 2015 levels would have decreased the fair value of our non-trading energy derivatives net asset by $11 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.

Interest Rate Risk

As of September 30, 2015, 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.

At September 30, 2015 and December 31, 2014, our floating-rate obligations aggregated $834 million and $532 million, respectively.

At September 30, 2015 and December 31, 2014, we had outstanding fixed-rate debt (excluding indexed debt securities) aggregating $7.7 billion and $8.2 billion, respectively, in principal amount and having a fair value of $8.3 billion and $8.9 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 $215 million if interest rates were to decline by 10% from their levels at September 30, 2015. 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 $152 million at September 30, 2015 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 $26 million if interest rates were to decline by 10% from levels at September 30, 2015. Changes in the fair value of the derivative component, a liability recorded at $454 million at September 30, 2015, 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 September 30, 2015 levels, the fair value of the derivative component would increase by approximately $8 million, which would be recorded as an unrealized loss in our Condensed Statements of Consolidated Income.

Equity Market Value Risk

We are exposed to equity market value risk through our ownership of 7.1 million shares of TW Common, 1.8 million shares of TWC Common and 0.9 million shares of Time Common, which we hold to facilitate our ability to meet our obligations under the ZENS. A decrease of 10% from the September 30, 2015 aggregate market value of these shares would result in a net loss of approximately $14 million, which would be recorded as an unrealized loss in our Condensed Statements of Consolidated Income.


Item 4.	CONTROLS AND PROCEDURES

In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our principal executive officer and principal financial officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of September 30, 2015 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

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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 September 30, 2015 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

PART II. OTHER INFORMATION


Item 1.	LEGAL PROCEEDINGS

For a description of certain legal and regulatory proceedings affecting CenterPoint Energy, please read Note 13(b) to our Interim Condensed Financial Statements and “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Future Sources and Uses of Cash” and “— Regulatory Matters,” each of which is incorporated herein by reference. See also “Business — Regulation” and “— Environmental Matters” in Item 1 and “Legal Proceedings” in Item 3 of our 2014 Form 10-K.


Item 1A.	RISK FACTORS

There have been no material changes from the risk factors disclosed in our 2014 Form 10-K.


Item 5.	OTHER INFORMATION

Ratio of Earnings to Fixed Charges. The ratio of earnings to fixed charges for the nine months ended September 30, 2015 and 2014 was 2.68 and 2.83, respectively. We do not believe that the ratios for these nine-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 Securities and Exchange Commission.

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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	Amended and Restated Bylaws of CenterPoint Energy	CenterPoint Energy’s Form 8-K dated July 24, 2014	1-31447	3.1
3.3	Statement of Resolutions Deleting Shares Designated Series A Preferred Stock of CenterPoint Energy	CenterPoint Energy’s Form 10-K for the year ended December 31, 2011	1-31447	3(c)
4.1	Form of CenterPoint Energy Stock Certificate	CenterPoint Energy’s Registration Statement on Form S-4	3-69502	4.1
4.2	$1,200,000,000 Credit Agreement, dated as of September 9, 2011, among CenterPoint Energy, as Borrower, and the banks named therein	CenterPoint Energy’s Form 8-K dated September 9, 2011	1-31447	4.1
4.3	$300,000,000 Credit Agreement, dated as of September 9, 2011, among CenterPoint Houston, as Borrower, and the banks named therein	CenterPoint Energy’s Form 8-K dated September 9, 2011	1-31447	4.2
4.4	$950,000,000 Credit Agreement, dated as of September 9, 2011, among CERC Corp., as Borrower, and the banks named therein	CenterPoint Energy’s Form 8-K dated September 9, 2011	1-31447	4.3
4.5	First Amendment to Credit Agreement, dated as of April 11, 2013, among CenterPoint Energy, as Borrower, and the banks named therein	CenterPoint Energy’s Form 8-K dated April 11, 2013	1-31447	4.1
4.6	First Amendment to Credit Agreement, dated as of April 11, 2013, among CERC Corp., as Borrower, and the banks named therein	CenterPoint Energy’s Form 8-K dated April 11, 2013	1-31447	4.2
4.7	Second Amendment to Credit Agreement, dated as of September 9, 2013, among CenterPoint Energy, as Borrower, and the banks named therein	CenterPoint Energy’s Form 8-K dated September 9, 2013	1-31447	4.1
4.8	First Amendment to Credit Agreement, dated as of September 9, 2013, among CenterPoint Houston, as Borrower, and the banks named therein	CenterPoint Energy’s Form 8-K dated September 9, 2013	1-31447	4.2
4.9	Second Amendment to Credit Agreement, dated as of September 9, 2013, among CERC Corp., as Borrower, and the banks named therein	CenterPoint Energy’s Form 8-K dated September 9, 2013	1-31447	4.3
4.10	Third Amendment to Credit Agreement, dated September 9, 2014, among CenterPoint Energy, as Borrower, and the banks named therein	CenterPoint Energy’s Form 8-K dated September 10, 2014	1-31447	4.1
4.11	Second Amendment to Credit Agreement, dated September 9, 2014, among CenterPoint Houston, as Borrower, and the banks named therein	CenterPoint Energy’s Form 8-K dated September 10, 2014	1-31447	4.2
4.12	Third Amendment to Credit Agreement, dated September 9, 2014 among CERC Corp., as Borrower, and the banks named therein	CenterPoint Energy’s Form 8-K dated September 10, 2014	1-31447	4.3

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Exhibit Number	Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference
+12	Computation of Ratios of Earnings to Fixed Charges
+31.1	Rule 13a-14(a)/15d-14(a) Certification of Scott M. Prochazka
+31.2	Rule 13a-14(a)/15d-14(a) Certification of William D. Rogers
+32.1	Section 1350 Certification of Scott M. Prochazka
+32.2	Section 1350 Certification of William D. Rogers
+101.INS	XBRL Instance Document
+101.SCH	XBRL Taxonomy Extension Schema Document
+101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
+101.DEF	XBRL Taxonomy Extension Definition Linkbase Document
+101.LAB	XBRL Taxonomy Extension Labels Linkbase Document
+101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

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SIGNATURES

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



	CENTERPOINT ENERGY, INC.


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

Date: November 5, 2015

Table of Contents

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	Amended and Restated Bylaws of CenterPoint Energy	CenterPoint Energy’s Form 8-K dated July 24, 2014	1-31447	3.1
3.3	Statement of Resolutions Deleting Shares Designated Series A Preferred Stock of CenterPoint Energy	CenterPoint Energy’s Form 10-K for the year ended December 31, 2011	1-31447	3(c)
4.1	Form of CenterPoint Energy Stock Certificate	CenterPoint Energy’s Registration Statement on Form S-4	3-69502	4.1
4.2	$1,200,000,000 Credit Agreement, dated as of September 9, 2011, among CenterPoint Energy, as Borrower, and the banks named therein	CenterPoint Energy’s Form 8-K dated September 9, 2011	1-31447	4.1
4.3	$300,000,000 Credit Agreement, dated as of September 9, 2011, among CenterPoint Houston, as Borrower, and the banks named therein	CenterPoint Energy’s Form 8-K dated September 9, 2011	1-31447	4.2
4.4	$950,000,000 Credit Agreement, dated as of September 9, 2011, among CERC Corp., as Borrower, and the banks named therein	CenterPoint Energy’s Form 8-K dated September 9, 2011	1-31447	4.3
4.5	First Amendment to Credit Agreement, dated as of April 11, 2013, among CenterPoint Energy, as Borrower, and the banks named therein	CenterPoint Energy’s Form 8-K dated April 11, 2013	1-31447	4.1
4.6	First Amendment to Credit Agreement, dated as of April 11, 2013, among CERC Corp., as Borrower, and the banks named therein	CenterPoint Energy’s Form 8-K dated April 11, 2013	1-31447	4.2
4.7	Second Amendment to Credit Agreement, dated as of September 9, 2013, among CenterPoint Energy, as Borrower, and the banks named therein	CenterPoint Energy’s Form 8-K dated September 9, 2013	1-31447	4.1
4.8	First Amendment to Credit Agreement, dated as of September 9, 2013, among CenterPoint Houston, as Borrower, and the banks named therein	CenterPoint Energy’s Form 8-K dated September 9, 2013	1-31447	4.2
4.9	Second Amendment to Credit Agreement, dated as of September 9, 2013, among CERC Corp., as Borrower, and the banks named therein	CenterPoint Energy’s Form 8-K dated September 9, 2013	1-31447	4.3
4.10	Third Amendment to Credit Agreement, dated September 9, 2014, among CenterPoint Energy, as Borrower, and the banks named therein	CenterPoint Energy’s Form 8-K dated September 10, 2014	1-31447	4.1
4.11	Second Amendment to Credit Agreement, dated September 9, 2014, among CenterPoint Houston, as Borrower, and the banks named therein	CenterPoint Energy’s Form 8-K dated September 10, 2014	1-31447	4.2
4.12	Third Amendment to Credit Agreement, dated September 9, 2014 among CERC Corp., as Borrower, and the banks named therein	CenterPoint Energy’s Form 8-K dated September 10, 2014	1-31447	4.3

Table of Contents



Exhibit Number	Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference
+12	Computation of Ratios of Earnings to Fixed Charges
+31.1	Rule 13a-14(a)/15d-14(a) Certification of Scott M. Prochazka
+31.2	Rule 13a-14(a)/15d-14(a) Certification of William D. Rogers
+32.1	Section 1350 Certification of Scott M. Prochazka
+32.2	Section 1350 Certification of William D. Rogers
+101.INS	XBRL Instance Document
+101.SCH	XBRL Taxonomy Extension Schema Document
+101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
+101.DEF	XBRL Taxonomy Extension Definition Linkbase Document
+101.LAB	XBRL Taxonomy Extension Labels Linkbase Document
+101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

CENTERPOINT ENERGY INC - FORM 10-Q - November 5, 2015

Attached files

CENTERPOINT ENERGY INC Reports