CENTERPOINT ENERGY RESOURCES CORP - FORM 10-Q

CENTERPOINT ENERGY RESOURCES CORP - FORM 10-Q - November 3, 2017

Attached files

Attached files

CENTERPOINT ENERGY RESOURCES CORP Reports

file	filename
EX-32.2 - EXHIBIT 32.2 - CENTERPOINT ENERGY RESOURCES CORP	cercexhibit322_9302017.htm
EX-32.1 - EXHIBIT 32.1 - CENTERPOINT ENERGY RESOURCES CORP	cercexhibit321_9302017.htm
EX-31.2 - EXHIBIT 31.2 - CENTERPOINT ENERGY RESOURCES CORP	cercexhibit312_9302017.htm
EX-31.1 - EXHIBIT 31.1 - CENTERPOINT ENERGY RESOURCES CORP	cercexhibit311_9302017.htm
EX-12 - EXHIBIT 12 - CENTERPOINT ENERGY RESOURCES CORP	cercexhibit12_9302017.htm
EX-4.4 - EXHIBIT 4.4 - CENTERPOINT ENERGY RESOURCES CORP	cercexhibit44_9302017.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, 2017
OR
¨	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 1-13265

______________________

CENTERPOINT ENERGY RESOURCES CORP.

(Exact name of registrant as specified in its charter)



Delaware	76-0511406
(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)

______________________

CenterPoint Energy Resources Corp. meets the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and is therefore filing this Form 10-Q with the reduced disclosure format.

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes þ No o

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



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

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

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

As of October 26, 2017, all 1,000 shares of CenterPoint Energy Resources Corp. common stock were held by Utility Holding, LLC, a wholly-owned subsidiary of CenterPoint Energy, Inc.

CENTERPOINT ENERGY RESOURCES CORP.

QUARTERLY REPORT ON FORM 10-Q

FOR THE QUARTER ENDED SEPTEMBER 30, 2017

TABLE OF CONTENTS



PART I.	FINANCIAL INFORMATION
		Page
Item 1.	Financial Statements	1

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

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

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

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

	Notes to Unaudited Condensed Consolidated Financial Statements	6

Item 2.	Management’s Narrative Analysis of Results of Operations	24

Item 4.	Controls and Procedures	34

PART II.	OTHER INFORMATION

Item 1.	Legal Proceedings	34

Item 1A.	Risk Factors	34

Item 5.	Other Information	34

Item 6.	Exhibits	35



GLOSSARY
AEM		Atmos Energy Marketing, LLC, previously a wholly-owned subsidiary of Atmos Energy Holdings, Inc., a wholly-owned subsidiary of Atmos Energy Corporation
AMAs		Asset Management Agreements
APSC		Arkansas Public Service Commission
ASU		Accounting Standards Update
Bcf		Billion cubic feet
BDA		Billing Determinant Adjustment, which is a revenue stabilization mechanism used to adjust revenues impacted by declines in natural gas consumption which occurred after the most recent rate case
CenterPoint Energy		CenterPoint Energy, Inc., and its subsidiaries
CERC Corp.		CenterPoint Energy Resources Corp.
CERC		CERC Corp., together with its subsidiaries
CES		CenterPoint Energy Services, Inc.
CIP		Conservation Improvement Program
Continuum		The retail energy services business of Continuum Retail Energy Services, LLC, including its wholly-owned subsidiary Lakeshore Energy Services, LLC and the natural gas wholesale assets previously owned by Continuum Energy Services, LLC
EECR		Energy Efficiency Cost Recovery
Enable		Enable Midstream Partners, LP
FASB		Financial Accounting Standards Board
Fitch		Fitch, Inc.
Form 10-Q		Quarterly Report on Form 10-Q
FRP		Formula Rate Plan
GenOn		GenOn Energy, Inc.
GRIP		Gas Reliability Infrastructure Program
Houston Electric		CenterPoint Energy Houston Electric, LLC and its subsidiaries
Interim Condensed Financial Statements		Condensed consolidated interim financial statements and notes
IRS		Internal Revenue Service
LIBOR		London Interbank Offered Rate
LPSC		Louisiana Public Service Commission
MGPs		Manufactured gas plants
MLP		Master Limited Partnership
MMBtu		One million British thermal units
Moody’s		Moody’s Investors Service, Inc.
MPSC		Mississippi Public Service Commission
MPUC		Minnesota Public Utilities Commission
NGD		Natural gas distribution business
NGLs		Natural gas liquids
NRG		NRG Energy, Inc.
OCC		Oklahoma Corporation Commission
OGE		OGE Energy Corp.
PBRC		Performance Based Rate Change
PHMSA		U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration
PRPs		Potentially responsible parties
Railroad Commission		Railroad Commission of Texas
Reliant Energy		Reliant Energy, Incorporated
ROE		Return on equity



GLOSSARY (cont.)
RRA		Rate Regulation Adjustment
RRI		Reliant Resources, Inc.
RSP		Rate Stabilization Plan
SEC		Securities and Exchange Commission
S&P		Standard & Poor’s Ratings Services, a division of The McGraw-Hill Companies
TBD		To be determined
Transition Agreements		Services Agreement, Employee Transition Agreement, Transitional Seconding Agreement and other agreements entered into in connection with the formation of Enable
VIE		Variable interest entity
2016 Form 10-K		Annual Report on Form 10-K for the year ended December 31, 2016

iii

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

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

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

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


•	the performance of Enable, the amount of cash distributions we receive from Enable, and the value of our interest in Enable, and factors that may have a material impact on such performance, cash distributions and value, including factors such as:


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

◦

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


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


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


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


◦	changes in tax status;


◦	access to debt and equity capital; and


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


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


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


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


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


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


•	tax reform and legislation;


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


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


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


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


•	the impact of unplanned facility outages;


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


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


•	our ability to control operation and maintenance costs;


•	actions by credit rating agencies;


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


•	the investment performance of CenterPoint Energy, Inc.’s pension and postretirement benefit plans;


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


•	changes in interest rates or rates of inflation;


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


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


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


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

•

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


•	acquisition and merger activities involving us or our competitors;


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


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


•	the outcome of litigation;


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


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


•	other factors we discuss in “Risk Factors” in Item 1A of Part I of our 2016 Form 10-K, which is incorporated herein by reference, and other reports we file from time to time with the SEC.

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

PART I. FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

(AN INDIRECT, WHOLLY-OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.)

CONDENSED STATEMENTS OF CONSOLIDATED INCOME

(Millions of Dollars)

(Unaudited)



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

Revenues:
Utility revenues	$	390		$	370		$	1,767		$	1,672
Non-utility revenues	861			608			2,964			1,433
Total	1,251			978			4,731			3,105

Expenses:
Utility natural gas	106			99			706			663
Non-utility natural gas	832			584			2,843			1,368
Operation and maintenance	187			175			603			571
Depreciation and amortization	68			62			202			185
Taxes other than income taxes	32			32			104			108
Total	1,225			952			4,458			2,895
Operating Income	26			26			273			210

Other Income (Expense):
Interest and other finance charges	(32		)	(29		)	(92		)	(93		)
Equity in earnings of unconsolidated affiliate, net	68			73			199			164
Other, net	1			(1		)	3			1
Total	37			43			110			72
Income Before Income Taxes	63			69			383			282
Income tax expense	25			26			144			113
Net Income	$	38		$	43		$	239		$	169

See Notes to Interim Condensed Consolidated Financial Statements

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

(AN INDIRECT, WHOLLY-OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.)

CONDENSED STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME

(Millions of Dollars)

(Unaudited)



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

Net income	$	38		$	43	$	239		$	169
Other comprehensive income, net of tax:
Adjustment to pension and other postretirement plans (net of tax of $2, $1, $2 and $-0-)	1			1		1			2
Net deferred loss from cash flow hedges (net of tax of $1, $-0-, $1 and $-0-)	(1		)	—		(1		)	—
Other comprehensive income	—			1		—			2
Comprehensive income	$	38		$	44	$	239		$	171

See Notes to Interim Condensed Consolidated Financial Statements

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

(AN INDIRECT, WHOLLY-OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.)

CONDENSED CONSOLIDATED BALANCE SHEETS

(Millions of Dollars)

(Unaudited)

ASSETS



	September 30, 2017		December 31, 2016
Current Assets:
Cash and cash equivalents	$	1	$	1
Accounts receivable, less bad debt reserve of $15 and $14, respectively	448		512
Accrued unbilled revenues	84		229
Accounts and notes receivable–affiliated companies	8		5
Materials and supplies	53		47
Natural gas inventory	252		131
Non-trading derivative assets	64		51
Prepaid expenses and other current assets	102		81
Total current assets	1,012		1,057

Property, Plant and Equipment:
Property, plant and equipment	6,694		6,351
Less: accumulated depreciation and amortization	1,995		1,782
Property, plant and equipment, net	4,699		4,569

Other Assets:
Goodwill	867		862
Non-trading derivative assets	56		19
Investment in unconsolidated affiliate	2,481		2,505
Other	261		206
Total other assets	3,665		3,592

Total Assets	$	9,376	$	9,218

See Notes to Interim Condensed Consolidated Financial Statements

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

(AN INDIRECT, WHOLLY-OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.)

CONDENSED CONSOLIDATED BALANCE SHEETS

(Millions of Dollars)

(Unaudited)

LIABILITIES AND STOCKHOLDER’S EQUITY



	September 30, 2017		December 31, 2016
Current Liabilities:
Short-term borrowings	$	48	$	35
Current portion of long-term debt	550		250
Accounts payable	375		471
Accounts and notes payable–affiliated companies	42		40
Taxes accrued	64		73
Interest accrued	33		33
Customer deposits	76		80
Non-trading derivative liabilities	17		41
Other	118		124
Total current liabilities	1,323		1,147

Other Liabilities:
Deferred income taxes, net	2,066		1,925
Non-trading derivative liabilities	10		5
Benefit obligations	105		104
Regulatory liabilities	699		769
Other	226		221
Total other liabilities	3,106		3,024

Long-Term Debt	2,086		2,125

Commitments and Contingencies (Note 12)

Stockholder’s Equity:
Common stock	—		—
Paid-in capital	2,528		2,489
Retained earnings	332		430
Accumulated other comprehensive income	1		3
Total stockholder’s equity	2,861		2,922

Total Liabilities and Stockholder’s Equity	$	9,376	$	9,218

See Notes to Interim Condensed Consolidated Financial Statements

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

(AN INDIRECT, WHOLLY-OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.)

CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

(Millions of Dollars)

(Unaudited)



	Nine Months Ended September 30,
	2017			2016
Cash Flows from Operating Activities:
Net income	$	239		$	169
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	202			185
Amortization of deferred financing costs	7			7
Deferred income taxes	140			108
Write-down of natural gas inventory	—			1
Equity in earnings of unconsolidated affiliate, net of distributions	(199		)	(164		)
Changes in other assets and liabilities, excluding acquisitions:
Accounts receivable and unbilled revenues, net	346			220
Accounts receivable/payable–affiliated companies	(1		)	(5		)
Inventory	(49		)	(1		)
Accounts payable	(227		)	(85		)
Fuel cost recovery	(30		)	(43		)
Interest and taxes accrued	(9		)	(8		)
Non-trading derivatives, net	(51		)	23
Margin deposits, net	(49		)	65
Other current assets	23			(11		)
Other current liabilities	(5		)	15
Other assets	(32		)	(5		)
Other liabilities	6			1
Other, net	1			2
Net cash provided by operating activities	312			474
Cash Flows from Investing Activities:
Capital expenditures	(373		)	(378		)
Distribution from unconsolidated affiliate in excess of cumulative earnings	223			223
Decrease in notes receivable–unconsolidated affiliate	—			363
Acquisitions, net of cash acquired	(132		)	(102		)
Other, net	2			(1		)
Net cash provided by (used in) investing activities	(280		)	105
Cash Flows from Financing Activities:
Decrease in short-term borrowings, net	13			3
Proceeds from (payments of) commercial paper, net	(40		)	240
Proceeds from long-term debt	298			—
Payments of long-term debt	—			(325		)
Dividends to parent	(337		)	(567		)
Debt issuance costs	(4		)	(1		)
Contribution from parent	38			73
Other, net	—			(2		)
Net cash used in financing activities	(32		)	(579		)
Net Increase in Cash and Cash Equivalents	—			—
Cash and Cash Equivalents at Beginning of Period	1			—
Cash and Cash Equivalents at End of Period	$	1		$	—
Supplemental Disclosure of Cash Flow Information:
Cash Payments:
Interest, net of capitalized interest	$	86		$	90
Income taxes, net	4			3
Non-cash transactions:
Accounts payable related to capital expenditures	$	53		$	32

See Notes to Interim Condensed Consolidated Financial Statements

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(1) Background and Basis of Presentation

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

Background. CERC Corp. is an indirect, wholly-owned subsidiary of CenterPoint Energy, a public utility holding company. CERC Corp.’s operating subsidiaries own and operate natural gas distribution facilities, supply natural gas to commercial and industrial customers and electric and natural gas utilities and own interests in Enable as described in Note 8. CERC Corp.’s operating subsidiaries and divisions include:


•	NGD, which owns and operates natural gas distribution systems in six states; and


•	CES, which obtains and offers competitive variable and fixed-price physical natural gas supplies and services primarily to commercial and industrial customers and electric and natural gas utilities in 33 states.

As of September 30, 2017, CERC Corp. also owned approximately 54.1% of the common units representing limited partner interests in Enable, which owns, operates and develops natural gas and crude oil infrastructure assets.

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.

CERC’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 CERC’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 CERC’s reportable business segments, see Note 14.

(2) New Accounting Pronouncements

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

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

In March 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). The new guidance simplifies several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification

on the statement of cash flows. CERC adopted this standard as of January 1, 2017. The adoption did not have a material impact on CERC’s financial position or results of operations. However, CERC’s statement of cash flows reflects a decrease in financing activity and a corresponding increase in operating activity of $1 million as of both September 30, 2017 and 2016 due to the retrospective application of the requirement that cash paid to a tax authority when shares are withheld to satisfy statutory income tax withholding obligations should be presented as a financing rather than as an operating activity.

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

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

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

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

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

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

In March 2017, the FASB issued ASU No. 2017-07, Compensation-Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires an employer to report the service cost component of the net periodic pension cost and postretirement benefit cost in the same line item(s) as other

employee compensation costs arising from services rendered during the period; all other components will be presented separately from the line item(s) that includes the service cost and outside of any subtotal of operating income. In addition, only the service cost component will be eligible for capitalization in assets. ASU 2017-07 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017, with early adoption permitted. ASU 2017-07 should be applied retrospectively for the presentation of the service cost component and the other components and prospectively for the capitalization of the service cost component. The adoption of this guidance is expected to result in an increase to operating income and a decrease to other income. Prospectively, other components previously capitalized in assets will be recorded as regulatory assets in CERC’s rate-regulated businesses. CERC does not believe this standard will have a material impact on its financial position, results of operations, cash flows and disclosures.

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

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

(3) Acquisition

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

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



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

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

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

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

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

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

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

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(in millions)
Operating Revenue	$	1,251	$	1,234	$	4,731	$	3,819
Net Income	38		43		239		173

(4) Employee Benefit Plans

CERC’s employees participate in CenterPoint Energy’s postretirement benefit plan. CERC’s net periodic cost includes the following components relating to postretirement benefits:



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2017			2016			2017			2016
	(in millions)
Service cost	$	1		$	1		$	1		$	1
Interest cost	1			1			3			3
Expected return on plan assets	(1		)	(1		)	(1		)	(1		)
Amortization of prior service cost	—			—			1			—
Net periodic cost (1)	$	1		$	1		$	4		$	3


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

CERC expects to contribute approximately $5 million to its postretirement benefit plan in 2017, of which approximately $1 million and $4 million were contributed during the three and nine months ended September 30, 2017, respectively.

(5) Regulatory Accounting

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

Currently, NGD estimates that total costs to restore natural gas distribution facilities damaged as a result of Hurricane Harvey will range from $25 million to $30 million and estimates that the total restoration costs covered by insurance will be approximately $17 million. NGD will defer the uninsured storm restoration costs as management believes it is probable that such costs will be recovered through traditional rate adjustment mechanisms for capital costs and through the next rate proceeding for operation and maintenance expenses. As of September 30, 2017, NGD has recorded approximately $7 million in regulatory assets, net of $2 million of insurance receivables recorded, for restoration costs incurred. As a result, storm restoration costs should not materially affect CERC’s reported net income for 2017.

(6) Derivative Instruments

CERC is exposed to various market risks. These risks arise from transactions entered into in the normal course of business. CERC utilizes derivative instruments such as physical forward contracts, swaps and options to mitigate the impact of changes in commodity prices, weather and interest rates on its operating results and cash flows. Such derivatives are recognized in CERC’s Condensed Consolidated Balance Sheets at their fair value unless CERC 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 CERC’s marketing, risk management services and hedging activities. The committee’s duties are to establish CERC’s commodity risk policies, allocate board-approved commercial risk limits, approve the use of new products and commodities, monitor positions and ensure compliance with CERC’s risk management policies, procedures and limits established by CenterPoint Energy’s board of directors.

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

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

CERC entered into heating-degree day swaps for certain NGD Texas jurisdictions to mitigate the effect of fluctuations from normal weather on its results of operations and cash flows for the 2017–2018 winter heating season, which contained a bilateral dollar cap of $8 million. However, CERC did not enter into heating-degree day swaps for NGD jurisdictions for the 2015–2016 or 2016–2017 winter heating seasons.

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

(b) Derivative Fair Values and Income Statement Impacts

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



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

Derivatives not designated as hedging instruments:
Natural gas derivatives (1) (2) (3)	Current Assets: Non-trading derivative assets	65		2
Natural gas derivatives (1) (2) (3)	Other Assets: Non-trading derivative assets	58		2
Natural gas derivatives (1) (2) (3)	Current Liabilities: Non-trading derivative liabilities	27		55
Natural gas derivatives (1) (2) (3)	Other Liabilities: Non-trading derivative liabilities	9		25
Total		$	164	$	84


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

(2)

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


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



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


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


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



Fair Value of Derivative Instruments
	December 31, 2016
Derivatives not designated as hedging instruments	Balance Sheet Location	Derivative Assets Fair Value		Derivative Liabilities Fair Value
		(in millions)
Natural gas derivatives (1) (2) (3)	Current Assets: Non-trading derivative assets	$	79	$	14
Natural gas derivatives (1) (2) (3)	Other Assets: Non-trading derivative assets	24		5
Natural gas derivatives (1) (2) (3)	Current Liabilities: Non-trading derivative liabilities	2		43
Natural gas derivatives (1) (2) (3)	Other Liabilities: Non-trading derivative liabilities	—		5
Total (4)		$	105	$	67


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

(2)

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


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


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



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


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


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

Realized and unrealized gains and losses on natural gas derivatives are recognized in the Condensed Statements of Consolidated Income as revenue for physical sales derivative contracts and as natural gas expense for financial natural gas derivatives and physical purchase natural gas derivatives.

Hedge ineffectiveness is recorded as a component of natural gas expense and primarily results from differences in the location of the derivative instrument and the hedged item. Basis ineffectiveness arises from natural gas market price differences between the locations of the hedged inventory and the delivery location specified in the hedge instruments. The impact of natural gas derivatives

designated as fair value hedges, the related hedged item, and natural gas derivatives not designated as hedging instruments are presented in the table below.



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

Derivatives not designated as hedging instruments:
Natural gas derivatives	Gains (Losses) in Revenues	$	30		$	31
Natural gas derivatives	Gains (Losses) in Expenses: Natural Gas	(9		)	(13		)
Total - derivatives not designated as hedging instruments		$	21		$	18



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

Derivatives not designated as hedging instruments:
Natural gas derivatives	Gains (Losses) in Revenues	$	162		$	1
Natural gas derivatives	Gains (Losses) in Expenses: Natural Gas	(91		)	35
Total - derivatives not designated as hedging instruments		$	71		$	36

(1)

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

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

(7) Fair Value Measurements

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

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

Level 2: Inputs, other than quoted prices included in Level 1, are observable for the asset or liability, either directly or indirectly. Level 2 inputs include quoted prices for similar instruments in active markets, and inputs other than quoted prices that are observable for the asset or liability. Fair value assets and liabilities that are generally included in this category are derivatives with fair values based on inputs from actively quoted markets. A market approach is utilized to value CERC’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 CERC’s judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. CERC develops these inputs based on the best information available, including CERC’s own data. A market approach is utilized to value CERC’s Level 3 assets or liabilities. As of September 30, 2017, CERC’s Level 3 assets and liabilities are comprised of physical natural gas forward contracts and options. Level 3 physical natural gas forward contracts are valued using a discounted cash flow model which includes illiquid forward price curve locations (ranging from $1.08 to $5.83 per MMBtu) as an unobservable input. Level 3 options are valued through Black-Scholes (including forward start) option models which include option volatilities (ranging from 0% to 87%) as an unobservable input. CERC’s Level 3 physical natural gas forward contracts and options derivative assets and liabilities consist of both long and short positions (forwards and options) and their fair value is sensitive to forward prices and volatilities. If forward prices decrease, CERC’s long forwards lose value whereas its short forwards gain in value. If volatility decreases, CERC’s long options lose value whereas its short options gain in value.

CERC determines the appropriate level for each financial asset and liability on a quarterly basis and recognizes transfers between levels at the end of the reporting period. For the nine months ended September 30, 2017, there were no transfers between Level 1 and 2. CERC 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 CERC’s assets and liabilities (including derivatives that are presented net) measured at fair value on a recurring basis as of September 30, 2017 and December 31, 2016, and indicate the fair value hierarchy of the valuation techniques utilized by CERC 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, 2017
	(in millions)
Assets
Corporate equities	$	3	$	—	$	—	$	—		$	3
Investments, including money market funds (2)	11		—		—		—			11
Natural gas derivatives (3)	3		128		33		(44		)	120
Hedged portion of natural gas inventory	65		—		—		—			65
Total assets	$	82	$	128	$	33	$	(44	)	$	199
Liabilities
Natural gas derivatives (3)	$	3	$	74	$	7	$	(57	)	$	27
Total liabilities	$	3	$	74	$	7	$	(57	)	$	27


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


(2)	Amounts are included in Other Assets in the Condensed Consolidated Balance Sheets.


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



	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Netting Adjustments (1)			Balance as of December 31, 2016
	(in millions)
Assets
Corporate equities	$	3	$	—	$	—	$	—		$	3
Investments, including money market funds (2)	10		—		—		—			10
Natural gas derivatives (3)	11		74		20		(35		)	70
Total assets	$	24	$	74	$	20	$	(35	)	$	83
Liabilities
Natural gas derivatives (3)	$	4	$	56	$	7	$	(21	)	$	46
Total liabilities	$	4	$	56	$	7	$	(21	)	$	46


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


(2)	Amounts are included in Other Assets in the Condensed Consolidated Balance Sheets.


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

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



	Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Derivative Assets and Liabilities, Net
	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(in millions)
Beginning balance	$	28		$	16		$	13		$	12
Purchases (1)	—			—			—			12
Total gains	(2		)	9			21			13
Total settlements	(1		)	(8		)	(5		)	(24		)
Transfers into Level 3	7			—			9			5
Transfers out of Level 3	(6		)	—			(12		)	(1		)
Ending balance (2)	$	26		$	17		$	26		$	17
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		$	17		$	14


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


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

Estimated Fair Value of Financial Instruments

The fair values of cash and cash equivalents 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 are stated at fair value and are excluded from the table below. The fair value of each debt instrument is determined by multiplying the principal amount of each debt instrument by a combination of historical trading prices and comparable issue data. These liabilities, which are not measured at fair value in the Condensed Consolidated Balance Sheets, but for which the fair value is disclosed, would be classified as Level 2 in the fair value hierarchy.



	September 30, 2017				December 31, 2016
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)
Financial liabilities:
Long-term debt	$	2,636	$	2,854	$	2,375	$	2,551

(8) Unconsolidated Affiliate

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

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

Transactions with Enable:



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


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



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

Limited Partner Interest in Enable:



	September 30, 2017
CERC Corp.	54.1	%
OGE	25.7	%

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

Enable Common Units Held:



	September 30, 2017
CERC Corp.	233,856,623
OGE	110,982,805

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

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

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

Summarized unaudited consolidated income information for Enable is as follows:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(in millions)
Operating revenues	$	705	$	620	$	1,997	$	1,658
Cost of sales, excluding depreciation and amortization	349		268		936		717
Impairment of goodwill and other long-lived assets	—		8		—		8
Operating income	137		139		399		299
Net income attributable to Enable	104		110		301		231

Reconciliation of Equity in Earnings, net:
CERC Corp.’s interest	$	56	$	61	$	163	$	128
Basis difference amortization (1)	12		12		36		36
CERC Corp.’s equity in earnings, net	$	68	$	73	$	199	$	164


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

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



	September 30, 2017			December 31, 2016
	(in millions)
Current assets	$	446		$	396
Non-current assets	10,816			10,816
Current liabilities	831			362
Non-current liabilities	2,740			3,056
Non-controlling interest	12			12
Preferred equity	362			362
Enable partners’ equity	7,317			7,420

Reconciliation of Equity Method Investment in Enable:
CERC Corp.’s ownership interest in Enable partners’ capital	$	4,007		$	4,067
CERC Corp.’s basis difference	(1,526		)	(1,562		)
CERC Corp.’s equity method investment in Enable	$	2,481		$	2,505

Distributions Received from Unconsolidated Affiliate:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(in millions)
Investment in Enable’s common units	$	74	$	74	$	223	$	223

As of September 30, 2017, CERC Corp. and OGE also own 40% and 60%, respectively, of the incentive distribution rights held by the general partner of Enable. Enable is expected to pay a minimum quarterly distribution of $0.2875 per common unit on its outstanding common units to the extent it has sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to its general partner and its affiliates, within 60 days after the end of each quarter. If cash distributions to Enable’s unitholders exceed $0.330625 per common unit in any quarter, the general partner will receive increasing percentages or incentive distributions rights, up to 50%, of the cash Enable distributes in excess of that amount. In certain circumstances the general partner of Enable will have the right to reset the minimum quarterly distribution and the target distribution levels at which the incentive distributions receive increasing percentages to higher levels based on Enable’s cash distributions at the time of the exercise of this reset election. To date, no incentive distributions have been made.

(9) Goodwill

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



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


(1)	See Note 3.


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

CERC performs its goodwill impairment tests at least annually and evaluates goodwill when events or changes in circumstances indicate that its carrying value may not be recoverable. The impairment evaluation for goodwill is performed using a two-step process.

In the first step, the fair value of each reporting unit is compared with the carrying amount of the reporting unit, including goodwill. The estimated fair value of the reporting unit is generally determined on the basis of discounted cash flows. If the estimated fair value of the reporting unit is less than the carrying amount of the reporting unit, then a second step must be completed to determine the amount of the goodwill impairment that should be recorded. In the second step, the implied fair value of the reporting unit’s goodwill is determined by allocating the reporting unit’s fair value to all of its assets and liabilities other than goodwill (including any unrecognized intangible assets) in a manner similar to a purchase price allocation. The resulting implied fair value of the goodwill that results from the application of this second step is then compared to the carrying amount of the goodwill and an impairment charge is recorded for the difference.

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

(10) Related Party Transactions

CERC participates in a money pool through which it 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 CenterPoint Energy’s revolving credit facility or the sale of CenterPoint Energy’s commercial paper. CERC had no investments in the money pool as of both September 30, 2017 and December 31, 2016, which would be included in accounts and notes receivable–affiliated companies in the Condensed Consolidated Balance Sheets. Affiliate related net interest income (expense) was not material for either the three or nine months ended September 30, 2017 or 2016.

CenterPoint Energy provides some corporate services to CERC. The costs of services have been charged directly to CERC using methods that management believes are reasonable. These methods include negotiated usage rates, dedicated asset assignment and proportionate corporate formulas based on operating expenses, assets, gross margin, employees and a composite of assets, gross margin and employees. Houston Electric provides a number of services to CERC. These services are billed at actual cost, either directly or as an allocation, and include fleet services, shop services, geographic services, surveying and right-of-way services, radio communications, data circuit management and field operations. Additionally, CERC provides certain services to Houston Electric. These services are billed at actual cost, either directly or as an allocation and include line locating and other miscellaneous services. These charges are not necessarily indicative of what would have been incurred had CERC not been an affiliate of CenterPoint Energy. Amounts charged to and by CERC for these services were as follows and are included primarily in operation and maintenance expenses:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(in millions)
Corporate service charges	$	30		$	31		$	93		$	90
Charges from Houston Electric for services provided	3			4			11			11
Billings to Houston Electric for services provided	(2		)	(2		)	(5		)	(5		)

See Note 8 for related party transactions with Enable.

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

(a)Short-term Borrowings

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


(b)	Long-term Debt

Debt Issuances. During the nine months ended September 30, 2017, CERC issued the following unsecured senior notes:



Issuance Date	Aggregate Principal Amount		Interest Rate	Maturity Date
	(in millions)
August 2017	$	300	4.10%	2047

The proceeds from the issuance of these unsecured senior notes were used for general corporate purposes and to repay a portion of outstanding commercial paper.

Revolving Credit Facility. In June 2017, CERC entered into an amendment to its revolving credit facility to extend the termination date thereof from March 3, 2021 to March 3, 2022 and to terminate the swingline loan subfacility thereunder. The amendment also increased the aggregate commitments by $300 million to $900 million under its revolving credit facility. In connection with the amendment to increase the aggregate commitments under its revolving credit facility, CERC increased the size of its commercial paper program to permit the issuance of commercial paper notes in an aggregate principal amount not to exceed $900 million at any time outstanding.

As of September 30, 2017 and December 31, 2016, CERC had the following revolving credit facility and utilization of such facility:



September 30, 2017									December 31, 2016
Size of Facility		Loans		Letters of Credit		Commercial Paper			Size of Facility		Loans		Letters of Credit		Commercial Paper
(in millions)
$	900	$	—	$	—	$	529	(1)	$	600	$	—	$	4	$	569	(1)


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



Execution Date	Size of Facility			Draw Rate of LIBOR plus (2)		Financial Covenant Limit on Debt for Borrowed Money to Capital Ratio		Debt for Borrowed Money to Capital Ratio as of September 30, 2017	Termination Date (3)
	(in millions)
March 3, 2016	$	900	(1)	1.25	%	65	%	38.6%	March 3, 2022


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


(2)	Based on current credit ratings.


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

CERC Corp. was in compliance with all financial debt covenants as of September 30, 2017.

(12) Commitments and Contingencies

(a) Natural Gas Supply Commitments

Natural gas supply commitments include natural gas contracts related to CERC’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 CERC’s Condensed Consolidated Balance Sheets as of September 30, 2017 and December 31, 2016 as these contracts meet an exception as “normal purchases contracts” or do not meet the definition of a derivative. Natural gas supply commitments

also include natural gas transportation contracts that do not meet the definition of a derivative. As of September 30, 2017, minimum payment obligations for natural gas supply commitments are approximately:



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

(b) Legal, Environmental and Other Matters

Legal Matters

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

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

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

Environmental Matters

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

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

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

Other Environmental. From time to time, CERC identifies the presence of environmental contaminants during its operations or on property where its predecessor companies have conducted operations. Other such sites involving contaminants may be identified in the future. CERC has and expects to continue to remediate identified sites consistent with its legal obligations. From time to time, CERC 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, CERC 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, CERC does not expect these matters, either individually or in the aggregate, to have a material adverse effect on its financial condition, results of operations or cash flows.

Other Proceedings

CERC 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, CERC 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. CERC regularly analyzes current information and, as necessary, provides accruals for probable and reasonably estimable liabilities on the eventual disposition of these matters. CERC does not expect the disposition of these matters to have a material adverse effect on its financial condition, results of operations or cash flows.

(13) Income Taxes

The effective tax rate reported for the three months ended September 30, 2017 was 40% compared to 38% for the same period in 2016. The effective tax rate reported for the nine months ended September 30, 2017 was 38% compared to 40% for the same period in 2016. The higher effective tax rate for the nine months ended September 30, 2016 was due to a Louisiana state tax law change resulting in an increase to CERC’s deferred tax liability.

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

(14) Reportable Business Segments

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

CERC’s reportable business segments include the following: Natural Gas Distribution, Energy Services, Midstream Investments and Other Operations. 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 CERC’s non-rate regulated gas sales and services operations. Midstream Investments consists of CERC’s equity investment in Enable. The Other Operations business segment includes unallocated corporate costs and inter-segment eliminations.

Financial data for business segments is as follows:



	For the Three Months Ended September 30, 2017
	Revenues from External Customers		Inter-segment Revenues			Operating Income
	(in millions)
Natural Gas Distribution	$	390	$	8		$	19
Energy Services	861		10			7
Midstream Investments (1)	—		—			—
Other Operations	—		—			—
Reconciling Eliminations	—		(18		)	—
Consolidated	$	1,251	$	—		$	26



	For the Three Months Ended September 30, 2016
	Revenues from External Customers		Inter-segment Revenues			Operating Income (Loss)
	(in millions)
Natural Gas Distribution	$	370	$	7		$	22
Energy Services	608		6			5
Midstream Investments (1)	—		—			—
Other Operations	—		—			(1		)
Reconciling Eliminations	—		(13		)	—
Consolidated	$	978	$	—		$	26



	For the Nine Months Ended September 30, 2017
	Revenues from External Customers		Inter-segment Revenues			Operating Income (Loss)			Total Assets as of September 30, 2017
	(in millions)
Natural Gas Distribution	$	1,767	$	24		$	220		$	6,067
Energy Services	2,964		34			58			1,337
Midstream Investments (1)	—		—			—			2,481
Other Operations	—		—			(5		)	73
Reconciling Eliminations	—		(58		)	—			(582		)
Consolidated	$	4,731	$	—		$	273		$	9,376



	For the Nine Months Ended September 30, 2016
	Revenues from External Customers		Inter-segment Revenues			Operating Income (Loss)			Total Assets as of December 31, 2016
	(in millions)
Natural Gas Distribution	$	1,672	$	21		$	202		$	6,099
Energy Services	1,433		17			11			1,102
Midstream Investments (1)	—		—			—			2,505
Other Operations	—		—			(3		)	75
Reconciling Eliminations	—		(38		)	—			(563		)
Consolidated	$	3,105	$	—		$	210		$	9,218


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



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

(15) Other Current Assets and Liabilities

Included in other current assets on the Condensed Consolidated Balance Sheets as of September 30, 2017 and December 31, 2016 were $22 million and less than $1 million, respectively, of margin deposits and $55 million and $40 million, respectively, of under-recovered gas cost. Included in other current liabilities on the Condensed Consolidated Balance Sheets at September 30, 2017 and December 31, 2016 were $2 million and $10 million, respectively, of over-recovered gas cost.

(16) Subsequent Events

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

Item 2. MANAGEMENT’S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS

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

We meet the conditions specified in General Instruction H(1)(a) and (b) to Form 10-Q and are therefore permitted to use the reduced disclosure format for wholly-owned subsidiaries of reporting companies. Accordingly, we have omitted from this report the information called for by Item 2 (Management’s Discussion and Analysis of Financial Condition and Results of Operations) and Item 3 (Quantitative and Qualitative Disclosures About Market Risk) of Part I and the following Part II items of Form 10-Q: Item 2 (Unregistered Sales of Equity Securities and Use of Proceeds), Item 3 (Defaults Upon Senior Securities) and Item 4 (Submission of Matters to a Vote of Security Holders). The following discussion explains material changes in our revenue and expense items between the three and nine months ended September 30, 2017 and the three and nine months ended September 30, 2016. Reference is made to “Management’s Narrative Analysis of Results of Operations” in Item 7 of our 2016 Form 10-K.

RECENT EVENTS

Hurricane Harvey. NGD suffered damage as a result of Hurricane Harvey, which struck the Texas coast on Friday, August 25, 2017. For further information regarding the impact of Hurricane Harvey, see Note 5 to our Interim Condensed Financial Statements.

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

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

CONSOLIDATED RESULTS OF OPERATIONS

Our results of operations are affected by seasonal fluctuations in the demand for natural gas and price movements of energy commodities as well as natural gas basis differentials. Our results of operations are also affected by, among other things, the actions of various federal, state and local governmental authorities having jurisdiction over rates we charge, competition in our various business operations, the effectiveness of our risk management activities, debt service costs and income tax expense. For more information regarding factors that may affect the future results of operations of our business, please read “Risk Factors” in Item 1A of Part I of our 2016 Form 10-K.

The following table sets forth our consolidated results of operations for the three and nine months ended September 30, 2017 and 2016, followed by a discussion of our consolidated results of operations.



	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(in millions)
Revenues	$	1,251		$	978		$	4,731		$	3,105
Expenses:
Natural gas	938			683			3,549			2,031
Operation and maintenance	187			175			603			571
Depreciation and amortization	68			62			202			185
Taxes other than income taxes	32			32			104			108
Total	1,225			952			4,458			2,895
Operating Income	26			26			273			210
Interest and other finance charges	(32		)	(29		)	(92		)	(93		)
Equity in earnings of unconsolidated affiliate, net	68			73			199			164
Other income, net	1			(1		)	3			1
Income Before Income Taxes	63			69			383			282
Income tax expense	25			26			144			113
Net Income	$	38		$	43		$	239		$	169

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

We reported net income of $38 million for the three months ended September 30, 2017 compared to net income of $43 million for the three months ended September 30, 2016.

The decrease in net income of $5 million was primarily due to the following key factors:


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


•	a $3 million increase in interest expense due to the issuance of $300 million of unsecured senior notes and higher weighted average commercial paper interest rates discussed further in Note 11 to our Interim Condensed Financial Statements.

These decreases in net income were partially offset by a $2 million increase in miscellaneous other non-operating income included in Other income, net shown above, and a $1 million decrease in income tax expense due to lower net income.

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

We reported net income of $239 million for the nine months ended September 30, 2017 compared to net income of $169 million for the nine months ended September 30, 2016.

The increase in net income of $70 million was primarily due to the following key factors:


•	a $63 million increase in operating income, discussed below by segment; and


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

These increases in net income were partially offset by a $31 million increase in income tax expense due to higher net income.

Income Tax Expense

Our effective tax rates reported for the three months ended September 30, 2017 was 40% compared to 38% for the same period in 2016. The effective tax rate reported for the nine months ended September 30, 2017 was 38% compared to 40% for the same

period in 2016. The higher effective tax rate for the nine months ended September 30, 2016 was due to a Louisiana state tax law change resulting in an increase to CERC’s deferred tax liability.

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, 2017 and 2016, followed by a discussion of the results of operations by business segment based on operating income. Included in revenues are intersegment sales. We account for intersegment sales as if the sales were to third parties at current market prices.



	Three Months Ended September 30,					Nine Months Ended September 30,
	2017		2016			2017			2016
	(in millions)
Natural Gas Distribution	$	19	$	22		$	220		$	202
Energy Services	7		5			58			11
Other Operations	—		(1		)	(5		)	(3		)
Total Consolidated Operating Income	$	26	$	26		$	273		$	210

Natural Gas Distribution

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

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



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

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

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

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


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


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


•	higher operation and maintenance expenses of $3 million.

These decreases were partially offset by the following:


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


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

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

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

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

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


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


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


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

These increases were partially offset by the following:


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


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


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

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

Energy Services

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

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



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

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

Throughput (in Bcf)	272		200			864		570

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


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


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

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

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

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

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

Midstream Investments

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

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



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

CERTAIN FACTORS AFFECTING FUTURE EARNINGS

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

LIQUIDITY AND CAPITAL RESOURCES

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 natural gas distribution operations. These capital expenditures are anticipated to maintain reliability and safety as well as expand our systems through value-added projects. Our principal anticipated cash requirements for the remaining three months of 2017 include approximately $153 million of capital expenditures, $250 million of maturing senior notes and restoration costs related to Hurricane Harvey.

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

Off-Balance Sheet Arrangements

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

Regulatory Matters

PHMSA Matters

On December 14, 2016, PHMSA announced an interim final rule to impose industry-developed recommendations as enforceable safety standards for downhole (underground) equipment, including wells, wellbore tubing, and casing, at both interstate and intrastate underground natural gas storage facilities. Both CERC and Enable own and operate underground storage facilities that are subject to this rule’s provisions, which include procedures and practices for operations, maintenance, threat identification, monitoring, assessment, site security, emergency response and preparedness, training and recordkeeping. This rule went into effect on January 18, 2017, with an announced compliance deadline of January 18, 2018. PHMSA determined, however, that it will not issue enforcement citations to any operators for violations of provisions of the interim final rule that had previously been non-mandatory provisions of American Petroleum Institute Recommended Practices 1170 and 1171 until one year after PHMSA issues a final rule, which it expects to publish in January of 2018. On October 19, 2017, PHMSA formally reopened the comment period on the interim final rule in response to a petition for reconsideration. This matter remains ongoing and subject to future PHMSA determinations. CERC and Enable will continue to monitor developments and assess the potential impact of any modifications to this rule.

Rate Change Applications

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



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


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


(2)	Amounts are recorded when approved.

Other Matters

Credit Facility

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

As of October 26, 2017, we had the following revolving credit facility and utilization of such facility:



Execution Date	Size of Facility		Amount Utilized at October 26, 2017			Termination Date
(in millions)
March 3, 2016	$	900	$	561	(1)	March 3, 2022

(1) Represents outstanding commercial paper.

Borrowings under our revolving credit facility are subject to customary terms and conditions. However, there is no requirement that we 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 our revolving credit facility are subject to acceleration upon the occurrence of events of default that we consider customary. The revolving credit facility also provides for customary fees, including commitment fees, administrative agent fees, fees in respect of letters of credit and other fees. In our revolving credit facility, the spread to LIBOR and the commitment fees fluctuate based on our credit rating. We are currently in compliance with the various business and financial covenants in our revolving credit facility.

Debt Financing Transactions

In August 2017, we issued $300 million aggregate principal amount of unsecured senior notes. For further information about our 2017 debt transactions, see Note 11 to our Interim Condensed Financial Statements.

Securities Registered with the SEC

On January 31, 2017, we filed a shelf registration statement with the SEC registering an indeterminate principal amount of our senior debt securities. The shelf registration statement will expire on January 31, 2020.

Temporary Investments

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

Money Pool

We participate in a money pool through which we and certain of our affiliates 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 by CenterPoint Energy under its revolving credit facility or the sale by CenterPoint Energy of its commercial paper. As of October 26, 2017, we had no borrowings from or investments in the money pool. The money pool may not provide sufficient funds to meet our cash needs.

Impact on Liquidity of a Downgrade in Credit Ratings

The interest on borrowings under our credit facility is based on our credit rating. On August 4, 2017, S&P revised its rating outlook on our senior debt to positive from developing and affirmed its rating. On September 24, 2017, Fitch revised its rating outlook on our senior debt to positive from stable and affirmed its rating.

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



Moody’s		S&P		Fitch
Rating	Outlook (1)	Rating	Outlook (2)	Rating	Outlook (3)
Baa2	Stable	A-	Positive	BBB	Positive


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


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


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

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

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

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

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

Cross Defaults

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

Possible Acquisitions, Divestitures and Joint Ventures

From time to time, we consider the acquisition or the disposition of assets or businesses or possible joint ventures, strategic initiatives or other joint ownership arrangements with respect to assets or businesses. Any determination to take action in this regard will be based on market conditions and opportunities existing at the time, and accordingly, the timing, size or success of any efforts

and the associated potential capital commitments are unpredictable. We may seek to fund all or part of any such efforts with proceeds from debt issuances. Debt financing may not, however, be available to us at that time due to a variety of events, including, among others, maintenance of our credit ratings, industry conditions, general economic conditions, market conditions and market perceptions.

In February 2016, CenterPoint Energy announced that it was evaluating strategic alternatives for our investment in Enable, including a sale or spin-off qualifying under Section 355 of the U.S. Internal Revenue Code. CenterPoint Energy has determined that it will no longer pursue the spin option. Should the sale option not be viable, we intend to reduce our ownership in Enable over time through a sale of the common units we hold in the public equity markets, subject to market conditions. There can be no assurances that these evaluations will result in any specific action, and we do not intend to disclose further developments on these initiatives unless and until CenterPoint Energy’s board of directors approves a specific action or as otherwise required.

Enable Midstream Partners

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

Weather Hedge

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

Hedging of Interest Expense for Future Debt Issuances

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

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 our credit facility;


•	various legislative or regulatory actions;


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


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


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


•	the outcome of litigation brought by or against us;


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


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

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

For information about the total debt to capitalization financial covenants in our revolving credit facility, see Note 11 to our Interim Condensed Financial Statements.

Relationship with CenterPoint Energy

We are an indirect, wholly-owned subsidiary of CenterPoint Energy. As a result of this relationship, the financial condition and liquidity of our parent company could affect our access to capital, our credit standing and our financial condition.

NEW ACCOUNTING PRONOUNCEMENTS

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

Item 4. CONTROLS AND PROCEDURES

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

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

PART II. OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

For a description of certain legal and regulatory proceedings affecting us, please read Note 12(b) to our Interim Condensed Financial Statements, each of which is incorporated herein by reference. See also “Business — Regulation” and “— Environmental Matters” in Item 1 and “Legal Proceedings” in Item 3 of our 2016 Form 10-K.

Item 1A. RISK FACTORS

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

Item 5. OTHER INFORMATION

Ratio of Earnings to Fixed Charges. The ratio of earnings to fixed charges for the nine months ended September 30, 2017 and 2016 was 5.27 and 4.51, respectively. We do not believe that the ratios for these nine-month periods are necessarily indicative of the ratios for the 12-month periods due to the seasonal nature of our business. The ratios were calculated pursuant to applicable rules of the SEC.

Item 6. EXHIBITS

The following exhibits are filed herewith:

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

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



Exhibit Number	Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference
3.1.1	Certificate of Incorporation of RERC Corp.	Form 10-K for the year ended December 31, 1997	1-13265	3(a)(1)
3.1.2	Certificate of Merger merging former NorAm Energy Corp. with and into HI Merger, Inc. dated August 6, 1997	Form 10-K for the year ended December 31, 1997	1-13265	3(a)(2)
3.1.3	Certificate of Amendment changing the name to Reliant Energy Resources Corp.	Form 10-K for the year ended December 31, 1998	1-13265	3(a)(3)
3.1.4	Certificate of Amendment changing the name to CenterPoint Energy Resources Corp.	Form 10-Q for the quarter ended June 30, 2003	1-13265	3(a)(4)
3.2	Bylaws of RERC Corp.	Form 10-K for the year ended December 31, 1997	1-13265	3(b)
4.1	$600,000,000 Credit Agreement, dated as of March 3, 2016, among CERC Corp., as Borrower, and the banks named therein	Form 8-K dated March 3, 2016	1-13265	4.3
4.2	First Amendment to Credit Agreement, dated as of June 16, 2017, among CERC Corp., as Borrower, and the banks named therein	Form 8-K dated June 16, 2017	1-13265	4.3
4.3	Indenture, dated as of February 1, 1998, between Reliant Energy Resources Corp. and Chase Bank of Texas, National Association, as Trustee	Form 8-K dated February 5, 1998	1-13265	4.1
+4.4	Supplemental Indenture No. 16 to Exhibit 4.3, dated as of August 23, 2017, providing for the issuance of CERC Corp.’s 4.10% Senior Notes due 2047
+12	Computation of Ratios of Earnings to Fixed Charges
+31.1	Rule 13a-14(a)/15d-14(a) Certification of Scott M. Prochazka
+31.2	Rule 13a-14(a)/15d-14(a) Certification of William D. Rogers
+32.1	Section 1350 Certification of Scott M. Prochazka
+32.2	Section 1350 Certification of William D. Rogers
+101.INS	XBRL Instance Document
+101.SCH	XBRL Taxonomy Extension Schema Document
+101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
+101.DEF	XBRL Taxonomy Extension Definition Linkbase Document
+101.LAB	XBRL Taxonomy Extension Labels Linkbase Document
+101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

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 RESOURCES CORP.


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

Date: November 3, 2017

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