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, 2007

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE TRANSITION PERIOD FROM                      TO                     .

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 is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o                     Accelerated filer o                     Non-accelerated filer þ

     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 31, 2007, 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, 2007

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION
Item 1. Financial Statements			1
Condensed Statements of Consolidated Income Three and Nine Months Ended September 30, 2006 and 2007 (unaudited)			1
Condensed Consolidated Balance Sheets December 31, 2006 and September 30, 2007 (unaudited)			2
Condensed Statements of Consolidated Cash Flows Nine Months Ended September 30, 2006 and 2007 (unaudited)			4
Notes to Unaudited Condensed Consolidated Financial Statements			5
Item 2. Management’s Narrative Analysis of the Results of Operations			17
Item 4. Controls and Procedures			28
PART II. OTHER INFORMATION
Item 1. Legal Proceedings			28
Item 1A. Risk Factors			28
Item 5. Other Information			29
Item 6. Exhibits			30
Computation of Ratio of Earnings to Fixed Charges
Rule 13a-14(a)/15d-14(a) Certification of David M. McClanahan
Rule 13a-14(a)/15d-14(a) Certification of Gary L. Whitlock
Section 1350 Certification of David M. McClanahan
Section 1350 Certification of Gary L. Whitlock
Items Incorporated by Reference

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

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

     We have based our forward-looking statements on our management’s beliefs and assumptions based on information 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 materially from those expressed or implied in forward-looking statements:

	•		state and federal legislative and regulatory actions or developments, including deregulation, re-regulation, changes in or application of laws or regulations applicable to the various aspects of our business;
	•		timely and appropriate rate actions and increases, allowing recovery of costs and a reasonable return on investment;
	•		industrial, commercial and residential growth in our service territory and changes in market demand and demographic patterns;
	•		the timing and extent of changes in commodity prices, particularly natural gas;
	•		the timing and extent of changes in the supply of natural gas;
	•		the timing and extent of changes in natural gas basis differentials;
	•		changes in interest rates or rates of inflation;
	•		weather variations and other natural phenomena;
	•		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;
	•		actions by rating agencies;
	•		effectiveness of our risk management activities;
	•		inability of various counterparties to meet their obligations to us;
	•		the ability of Reliant Energy, Inc. (RRI) to satisfy its obligations to us in connection with the contractual arrangements pursuant to which we are their guarantor;
	•		the outcome of litigation brought by or against us;
	•		our ability to control costs;
	•		the investment performance of CenterPoint Energy, Inc.’s employee benefit plans;

	•		our potential business strategies, including acquisitions or dispositions of assets or businesses, which we cannot assure will be completed or will have the anticipated benefits to us; and
	•		other factors we discuss in “Risk Factors” in Item 1A of Part I of our Annual Report on Form 10-K for the year ended December 31, 2006, which is incorporated herein by reference, in “Risk Factors” in Item 1A of Part II of this Quarterly Report on Form 10-Q and in other reports we file from time to time with the Securities and Exchange Commission.

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

PART I. FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.)

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2006				2007				2006				2007
Revenues		$	1,400			$	1,351			$	5,474			$	5,614
Expenses:
Natural gas			1,058				990				4,286				4,348
Operation and maintenance			192				191				588				577
Depreciation and amortization			50				56				150				159
Taxes other than income taxes			31				23				116				106
Total			1,331				1,260				5,140				5,190
Operating Income			69				91				334				424
Other Income (Expense):
Interest and other finance charges			(43	)			(51	)			(125	)			(135	)
Other, net			7				7				15				14
Total			(36	)			(44	)			(110	)			(121	)
Income Before Income Taxes			33				47				224				303
Income tax expense			(20	)			(19	)			(91	)			(114	)
Net Income		$	13			$	28			$	133			$	189

See Notes to the Company’s Interim Condensed Consolidated Financial Statements

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.)

ASSETS

		December 31,				September 30,
		2006				2007
Current Assets:
Cash and cash equivalents		$	5			$	3
Accounts and notes receivable, net			846				485
Accrued unbilled revenue			356				108
Accounts and notes receivable – affiliated companies			198				43
Materials and supplies			31				33
Natural gas inventory			305				451
Non-trading derivative assets			98				44
Taxes receivable			—				47
Deferred tax asset			2				—
Prepaid expenses and other current assets			360				311
Total current assets			2,201				1,525
Property, Plant and Equipment:
Property, plant and equipment			5,336				5,666
Less accumulated depreciation and amortization			(697	)			(712	)
Property, plant and equipment, net			4,639				4,954
Other Assets:
Goodwill			1,705				1,705
Non-trading derivative assets			21				10
Notes receivable from unconsolidated affiliates			—				51
Other			249				254
Total other assets			1,975				2,020
Total Assets		$	8,815			$	8,499

See Notes to the Company’s Interim Condensed Consolidated Financial Statements

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.)
CONDENSED CONSOLIDATED BALANCE SHEETS — (Continued)
(Millions of Dollars)
(Unaudited)

LIABILITIES AND STOCKHOLDER’S EQUITY

		December 31,				September 30,
		2006				2007
Current Liabilities:
Short-term borrowings		$	187			$	150
Current portion of long-term debt			7				307
Accounts payable			928				393
Accounts and notes payable — affiliated companies			386				200
Taxes accrued			115				83
Interest accrued			48				52
Customer deposits			62				56
Non-trading derivative liabilities			141				81
Other			305				178
Total current liabilities			2,179				1,500
Other Liabilities:
Accumulated deferred income taxes, net			662				721
Non-trading derivative liabilities			80				42
Benefit obligations			138				128
Other			669				642
Total other liabilities			1,549				1,533
Long-term Debt			2,155				2,358
Commitments and Contingencies (Note 10)
Stockholder’s Equity:
Common stock			—				—
Paid-in capital			2,403				2,405
Retained earnings			505				694
Accumulated other comprehensive income			24				9
Total stockholder’s equity			2,932				3,108
Total Liabilities and Stockholder’s Equity		$	8,815			$	8,499

See Notes to the Company’s Interim Condensed Consolidated Financial Statements

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.)

		Nine Months Ended September 30,
		2006				2007
Cash Flows from Operating Activities:
Net income		$	133			$	189
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization			150				159
Amortization of deferred financing costs			6				6
Deferred income taxes			33				60
Write-down of natural gas inventory			56				11
Changes in other assets and liabilities:
Accounts receivable and unbilled revenues, net			828				609
Accounts receivable/payable, affiliates			3				16
Inventory			(52	)			(159	)
Taxes receivable			(54	)			(47	)
Accounts payable			(625	)			(446	)
Fuel cost recovery			106				(90	)
Interest and taxes accrued			17				(28	)
Non-trading derivatives, net			(38	)			14
Margin deposits, net			(176	)			49
Short-term risk management activities, net			3				—
Other current assets			(79	)			(31	)
Other current liabilities			(12	)			(30	)
Other assets			(16	)			(27	)
Other liabilities			(8	)			(56	)
Other, net			(14	)			—
Net cash provided by operating activities			261				199
Cash Flows from Investing Activities:
Capital expenditures			(332	)			(519	)
Increase in notes receivable from unconsolidated affiliates			—				(51	)
Investment in unconsolidated affiliates			(6	)			(40	)
Other, net			24				(10	)
Net cash used in investing activities			(314	)			(620	)
Cash Flows from Financing Activities:
Decrease in short-term borrowings, net			—				(37	)
Long-term revolving credit facilities, net			—				360
Proceeds from issuance of long-term debt			324				150
Payments of long-term debt			(6	)			(7	)
Decrease in notes payable to affiliates			(289	)			(47	)
Debt issuance costs			(1	)			(2	)
Contribution from parent			112				—
Other, net			1				2
Net cash provided by financing activities			141				419
Net Increase (Decrease) in Cash and Cash Equivalents			88				(2	)
Cash and Cash Equivalents at Beginning of Period			31				5
Cash and Cash Equivalents at End of Period		$	119			$	3
Supplemental Disclosure of Cash Flow Information:
Cash Payments:
Interest, net of capitalized interest		$	115			$	123
Income taxes (refunds), net			(8	)			129
Non-cash transactions:
Increase in accounts payable related to capital expenditures			34				—

See Notes to the Company’s 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 Quarterly Report on Form 10-Q (Form 10-Q) of CenterPoint Energy Resources Corp. are the condensed consolidated interim financial statements and notes (Interim Condensed Financial Statements) of CenterPoint Energy Resources Corp. and its subsidiaries (collectively, CERC Corp. or the Company). The Interim Condensed Financial Statements are unaudited, omit certain financial statement disclosures and should be read with the Annual Report on Form 10-K of CERC Corp. for the year ended December 31, 2006 (CERC Corp. Form 10-K).

     Background. The Company owns and operates natural gas distribution systems in six states. Wholly owned subsidiaries of the Company own interstate natural gas pipelines and gas gathering systems and provide various ancillary services. Another wholly owned subsidiary of the Company offers variable and fixed-price physical natural gas supplies primarily to commercial and industrial customers and electric and gas utilities.

     The Company is an indirect wholly owned subsidiary of CenterPoint Energy, Inc. (CenterPoint Energy), a public utility holding company.

     Basis of Presentation. The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and 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.

     The Company’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 the Company’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. In addition, business segment information for the three and nine months ended September 30, 2006 has been recast to conform to the 2007 presentation due to the change in reportable business segments in the fourth quarter of 2006. The business segment detail revised as a result of the new reportable business segments did not affect consolidated operating income for any period presented.

     For a description of the Company’s reportable business segments, reference is made to Note 12.

(2) New Accounting Pronouncements

     In July 2006, the Financial Accounting Standards Board (FASB) issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109” (FIN 48). FIN 48 clarifies the accounting for uncertain income tax positions and requires the Company to recognize management’s best estimate of the impact of a tax position if it is considered “more likely than not,” as defined in Statement of Financial Accounting Standards (SFAS) No. 5, “Accounting for Contingencies,” of being sustained on audit based solely on the technical merits of the position. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The cumulative effect of adopting FIN 48 as of January 1, 2007 was a credit to retained earnings of less than $1 million. The Company recognizes interest and penalties as a component of income taxes.

     The implementation of FIN 48 also affected other balance sheet accounts. The balance sheet as of January 1, 2007, upon adoption, would have reflected approximately $0.7 million of net unrecognized tax benefits in “Other Liabilities.” This amount includes $0.6 million reclassified from accumulated deferred income taxes to the liability for uncertain tax positions and $9.0 million representing amounts accrued for uncertain tax positions that, if recognized, would reduce the effective income tax rate. These liabilities were partially offset by a refund claim of $8.9 million. In addition to these amounts, the Company, at January 1, 2007, accrued approximately $1.3 million for the payment of interest for these uncertain tax positions.

     In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (SFAS No. 157). SFAS No. 157 establishes a framework for measuring fair value and requires expanded disclosure about the information used to measure fair value. The statement applies whenever other statements require or permit assets or liabilities to be measured at fair value. The statement does not expand the use of fair value accounting in any new circumstances and is effective for the Company for the year ended December 31, 2008 and for interim periods included in that year, with early adoption encouraged. The Company is currently evaluating the effect of adoption of this new standard on its financial position, results of operations and cash flows.

     In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities, including an amendment of FASB Statement No. 115” (SFAS No. 159). SFAS No. 159 permits the Company to choose, at specified election dates, to measure eligible items at fair value (the “fair value option”). The Company would report unrealized gains and losses on items for which the fair value option has been elected in earnings at each subsequent reporting period. This accounting standard is effective as of the beginning of the first fiscal year that begins after November 15, 2007. The Company is currently evaluating the effect of adoption of this new standard on its financial position, results of operations and cash flows.

(3) Employee Benefit Plans

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

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2006				2007				2006				2007
						(in millions)
Service cost		$	—			$	1			$	1			$	1
Interest cost			2				1				5				5
Expected return on plan assets			—				(1	)			(1	)			(1	)
Amortization of prior service cost			—				1				1				2
Other			—				—				1				—
Net periodic cost		$	2			$	2			$	7			$	7

     The Company expects to contribute approximately $16 million to its postretirement benefits plan in 2007, of which $12 million had been contributed as of September 30, 2007.

(4) Regulatory Matters

(a) Rate Cases

     Arkansas.  In January 2007, the Company’s natural gas distribution business (Gas Operations) filed an application with the Arkansas Public Service Commission (APSC) to change its natural gas distribution rates. This filing seeks approval to change the base rate portion of a customer’s natural gas bill, which makes up about 30 percent of the total bill and covers the cost of distributing natural gas. The filing does not apply to the gas supply rate, which makes up the remaining approximately 70 percent of the bill.

     The January filing requested an increase in annual base revenues of approximately $51 million. Gas Operations subsequently agreed to reduce its request to approximately $40 million. As part of the base rate filing, Gas Operations also proposed a revenue stabilization tariff (also known as decoupling) that would help stabilize revenues and eliminate the potential conflict between its efforts to earn a reasonable return on invested capital while promoting energy efficiency initiatives, because decoupling mitigates the negative effects of declining customer usage. As part of the revenue stabilization tariff, Gas Operations proposed to reduce the requested return on equity by 35 basis points which would reduce the base rate increase by $1 million.

     In September 2007, the APSC staff and Gas Operations entered into and filed with the APSC a Stipulation and Settlement Agreement (Settlement Agreement) and a joint motion requesting APSC approval of the Settlement Agreement. Under the terms of the Settlement Agreement, the annual base revenues of Gas Operations would increase by approximately $20 million, and the revenue stabilization tariff would be allowed to go into effect upon approval of the Settlement Agreement, with an authorized rate of return on equity of 9.65% (which reflects a reduction of 10 basis points for the implementation of the revenue stabilization tariff). The other parties to the proceeding have agreed not to oppose the Settlement Agreement. In October 2007, an order approving the

Settlement Agreement was issued by the APSC. The new rates became effective with bills rendered on and after November 1, 2007.

     Texas.  In September 2006, Gas Operations filed statements of intent with 47 cities in its Texas coast service territory to increase miscellaneous service charges and to allow recovery of the costs of financial hedging transactions through its purchased gas cost adjustment. In November 2006, these changes became effective as all 47 cities either approved the filings or took no action, thereby allowing rates to go into effect by operation of law. In December 2006, Gas Operations filed a statement of intent with the Railroad Commission of Texas (Railroad Commission) seeking to implement such changes in the environs of the Texas coast service territory. The Railroad Commission approved the filing in April 2007. The new service charges were implemented in the second quarter of 2007.

     Minnesota.  As of September 30, 2006, Gas Operations had recorded approximately $45 million as a regulatory asset related to prior years’ unrecovered purchased gas costs in its Minnesota service territory. Of the total, approximately $24 million related to the period from July 1, 2004 through June 30, 2006, and approximately $21 million related to the period from July 1, 2000 through June 30, 2004. The amounts related to periods prior to July 1, 2004 arose as a result of revisions to the calculation of unrecovered purchased gas costs previously approved by the Minnesota Public Utilities Commission (MPUC). Recovery of this regulatory asset was dependent upon obtaining a waiver from the MPUC rules. In November 2006, the MPUC considered the request and voted to deny the waiver. Accordingly, the Company recorded a $21 million adjustment to reduce pre-tax earnings in the fourth quarter of 2006 and reduced the regulatory asset by an equal amount. In February 2007, the MPUC denied reconsideration. In March 2007, the Company petitioned the Minnesota Court of Appeals for review of the MPUC’s decision. No prediction can be made as to the ultimate outcome of this matter.

     In November 2005, Gas Operations filed a request with the MPUC to increase annual base rates by approximately $41 million. In December 2005, the MPUC approved an interim rate increase of approximately $35 million that was implemented January 1, 2006. Any excess of amounts collected under the interim rates over the amounts approved as final rates was subject to refund to customers. In October 2006, the MPUC considered the request and indicated that it would grant a rate increase of approximately $21 million. In addition, the MPUC approved a $5 million affordability program to assist low-income customers, the actual cost of which will be recovered in rates in addition to the $21 million rate increase. A final order was issued in January 2007, and final rates were implemented beginning May 1, 2007. Gas Operations completed refunding the proportional share of the excess of the amounts collected in interim rates over the amount allowed by the final order to customers in the second quarter of 2007.

(b) APSC Affiliate Transaction Rulemaking Proceeding

     In December 2006, the APSC adopted new rules governing affiliate transactions involving public utilities operating in Arkansas. In February 2007, in response to requests by the Company and other gas and electric utilities operating in Arkansas, the APSC granted reconsideration of the rules and stayed their operation in order to permit additional consideration. In May 2007, the APSC adopted revised rules, which incorporated many revisions proposed by the utilities, the Arkansas Attorney General and the APSC staff. The revised rules prohibit affiliated financing transactions for purposes not related to utility operations, but permit the continuation of existing money pool and multi-jurisdictional financing arrangements such as those currently in place at the Company. Non-financial affiliate transactions generally have to be priced under an asymmetrical pricing formula under which utilities would benefit from any difference between the cost of providing goods and services to or from the utility operations and the market value of those goods or services. However, corporate services provided at fully allocated cost such as those provided by service companies are exempt. The rules also restrict utilities from engaging in businesses other than utility and utility-related businesses if the total book value of non-utility businesses exceeds 10 percent of the book value of the utility and its affiliates. However, existing businesses are grandfathered under the revised rules. The revised rules also permit utilities to petition for waivers of financing and non-financial rules that would otherwise be applicable to their transactions.

     The APSC’s revised rules impose record keeping, record access, employee training and reporting requirements related to affiliate transactions, including notification to the APSC of the formation of new affiliates that will engage in transactions with the utility and annual certification by the utility’s president or chief executive officer and its chief financial officer of compliance with the rules. In addition, the revised rules require a report to the APSC in the event the utility’s bond rating is downgraded in certain circumstances. Although the revised rules impose new requirements on the Company’s operations in Arkansas, at this time the Company does not anticipate that the

revised rules will have an adverse effect on existing operations in Arkansas. In September 2007, Gas Operations made a filing with the APSC in accordance with the revised rules to document existing practices that would be covered by grandfathering provisions of those rules.

(5) Derivative Instruments

     The Company is exposed to various market risks. These risks arise from transactions entered into in the normal course of business. The Company utilizes derivative instruments such as physical forward contracts, swaps and options (energy derivatives) to mitigate the impact of changes in its natural gas businesses on its operating results and cash flows.

 Non-Trading Activities

     Cash Flow Hedges.  The Company enters into certain derivative instruments that qualify as cash flow hedges under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS No. 133). The objective of these derivative instruments is to hedge the price risk associated with natural gas purchases and sales to reduce cash flow variability related to meeting the Company’s wholesale and retail customer obligations. During the nine months ended September 30, 2006 and 2007, hedge ineffectiveness resulted in a gain of less than $1 million and a loss of less than $1 million, respectively, from derivatives that qualify for and are designated as cash flow hedges. No component of the derivative instruments’ gain or loss was excluded from the assessment of effectiveness. If it becomes probable that an anticipated transaction being hedged will not occur, the Company realizes in net income the deferred gains and losses previously recognized in accumulated other comprehensive loss. When an anticipated transaction being hedged affects earnings, the accumulated deferred gain or loss recognized in accumulated other comprehensive loss is reclassified and included in the Condensed Statements of Consolidated Income under the “Expenses” caption “Natural gas.” Cash flows resulting from these transactions in non-trading energy derivatives are included in the Condensed Statements of Consolidated Cash Flows in the same category as the item being hedged. As of September 30, 2007, the Company expects $15 million ($10 million after-tax) in accumulated other comprehensive income to be reclassified as a decrease in natural gas expense during the next twelve months.

     The length of time the Company is hedging its exposure to the variability in future cash flows using financial instruments is primarily two years, with a limited amount up to four years. The Company’s policy is not to exceed ten years in hedging its exposure.

     Other Derivative Instruments.  The Company enters into certain derivative instruments to manage physical commodity price risks that do not qualify or are not designated as cash flow or fair value hedges under SFAS No. 133. The Company utilizes these financial instruments to manage physical commodity price risks and does not engage in proprietary or speculative commodity trading. During the three months ended September 30, 2006 and 2007, the Company recognized unrealized net gains of $20 million and $2 million, respectively. During the nine months ended September 30, 2006 and 2007, the Company recognized unrealized net gains of $33 million and net losses of $12 million, respectively. These derivative gains and losses are included in the Condensed Statements of Consolidated Income under the “Expenses” caption “Natural gas.”

(6) Goodwill

     Goodwill by reportable business segment as of both December 31, 2006 and September 30, 2007 is as follows (in millions):

Natural Gas Distribution		$	746
Interstate Pipelines			579
Competitive Natural Gas Sales and Services			335
Field Services			25
Other Operations			20
Total		$	1,705

     The Company performs its goodwill impairment tests at least annually and evaluates goodwill when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable. The impairment evaluation for goodwill is performed by using a two-step process. In the first step, the fair value of each reporting unit is compared with the carrying amount of the reporting unit, including goodwill. The estimated fair value of the

reporting unit is generally determined on the basis of discounted future 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 in order 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.

     The Company performed the test at July 1, 2007, the Company’s annual impairment testing date, and determined that no impairment charge for goodwill was required.

(7) Comprehensive Income

     The following table summarizes the components of total comprehensive income (net of tax):

		For the Three Months Ended								For the Nine Months Ended
		September 30,								September 30,
		2006				2007				2006				2007
						(in millions)
Net income		$	13			$	28			$	133			$	189
Other comprehensive income (loss):
Adjustment to pension and other postretirement plans (net of tax of $-0-)			—				—				—				1
Net deferred gain (loss) from cash flow hedges (net of tax of $7, $3, $5 and $6)			10				6				5				11
Reclassification of deferred loss (gain) from cash flow hedges realized in net income (net of tax of $2, ($4) and ($17))			1				—				(3	)			(27	)
Total			11				6				2				(15	)
Comprehensive income		$	24			$	34			$	135			$	174

     The following table summarizes the components of accumulated other comprehensive income (loss):

		December 31,				September 30,
		2006				2007
		(in millions)
SFAS No. 158 incremental effect		$	(2	)		$	(1	)
Net deferred gain from cash flow hedges			26				10
Total accumulated other comprehensive income (loss)		$	24			$	9

(8) Related Party Transactions

     The Company 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. As of December 31, 2006 and September 30, 2007, the Company had borrowings from the money pool of $186 million and $139 million, respectively.

     For the three months ended September 30, 2006 and 2007, the Company had net interest expense related to affiliate borrowings of less than $1 million, and approximately $2 million, respectively. For the nine months ended September 30, 2006 and 2007, the Company had net interest expense related to affiliate borrowings of approximately $1 million and $3 million, respectively.

     CenterPoint Energy provides some corporate services to the Company. The costs of services have been charged directly to the Company using methods that management believes to be 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. These charges are not necessarily indicative of what would have been incurred had the Company not been an affiliate. Amounts charged to the Company for these services were $31 million and $34 million for the three months ended September

30, 2006 and 2007, respectively, and $95 million and $99 million for the nine months ended September 30, 2006 and 2007, respectively, and are included primarily in operation and maintenance expenses.

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

(a) Short-term Borrowings

     In October 2007, the Company amended its receivables facility and extended the termination date to October 28, 2008. The facility size will range from $150 million to $375 million during the period from September 30, 2007 to the October 28, 2008 termination date. The variable size of the facility was designed to track the seasonal pattern of receivables in the Company’s natural gas businesses. At September 30, 2007, the facility size was $150 million. Commencing with an October 2006 amendment to the receivables facility, the provisions for sale accounting under SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities,” were no longer met. Accordingly, advances received by the Company upon the sale of receivables are accounted for as short-term borrowings as of December 31, 2006 and September 30, 2007. As of December 31, 2006 and September 30, 2007, $187 million and $150 million, respectively, was advanced for the purchase of receivables under the Company’s receivables facility.

(b) Long-term Debt

     Senior Notes. In February 2007, the Company issued $150 million aggregate principal amount of 6.25% senior notes due in February 2037. The proceeds from the sale of the senior notes were used to repay advances for the purchase of receivables under the Company’s receivables facility. Such repayment provided increased liquidity and capital resources for general corporate purposes.

     In October 2007, the Company issued $250 million aggregate principal amount of 6.125% senior notes due in November 2017 and $250 million aggregate principal amount of 6.625% senior notes due in November 2037. The proceeds from the sale of the senior notes will be used for general corporate purposes, including repayment or refinancing of debt, including $300 million of the Company’s 6.5% senior notes due February 1, 2008, capital expenditures, working capital and loans to or investments in affiliates. Pending application of the proceeds for these purposes, the Company repaid borrowings under its revolving credit and receivables facilities.

     Revolving Credit Facility. In June 2007, the Company entered into an amended and restated bank credit facility. The Company’s amended credit facility is a $950 million five-year senior unsecured revolving credit facility versus a $550 million facility prior to the amendment. The facility’s first drawn cost remains at the London Interbank Offered Rate (LIBOR) plus 45 basis points based on the Company’s current credit ratings.

     Under the credit facility, an additional utilization fee of 5 basis points applies to borrowings any time more than 50% of the facility is utilized. The spread to LIBOR and the utilization fee fluctuate based on the Company’s credit ratings.

     As of September 30, 2007, the Company had $360 million of borrowings and approximately $19 million of outstanding letters of credit under its $950 million credit facility. The Company was in compliance with all covenants as of September 30, 2007.

(10) Commitments and Contingencies

(a) Natural Gas Supply Commitments

     Natural gas supply commitments include natural gas contracts related to the Company’s Natural Gas Distribution and Competitive Natural Gas Sales and Services business segments, which have various quantity requirements and durations, that are not classified as non-trading derivative assets and liabilities in the Company’s Consolidated Balance Sheets as of December 31, 2006 and September 30, 2007 as these contracts meet the SFAS No. 133 exception to be classified 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, 2007, minimum payment obligations for natural gas supply commitments are approximately $436 million for the remaining three months in 2007, $734 million in 2008, $283 million in 2009, $276 million in 2010, $274 million in 2011 and $1.3 billion in 2012 and thereafter.

(b) Legal, Environmental and Other Regulatory Matters

Legal Matters

     Natural Gas Measurement Lawsuits.  CERC Corp. and certain of its subsidiaries are defendants in a lawsuit filed in 1997 under the Federal False Claims Act alleging mismeasurement of natural gas produced from federal and Indian lands. The suit seeks undisclosed damages, along with statutory penalties, interest, costs and fees. The complaint is part of a larger series of complaints filed against 77 natural gas pipelines and their subsidiaries and affiliates. An earlier single action making substantially similar allegations against the pipelines was dismissed by the federal district court for the District of Columbia on grounds of improper joinder and lack of jurisdiction. As a result, the various individual complaints were filed in numerous courts throughout the country. This case has been consolidated, together with the other similar False Claims Act cases, in the federal district court in Cheyenne, Wyoming. On October 20, 2006, the judge considering this matter granted the defendants’ motion to dismiss the suit on the ground that the court lacked subject matter jurisdiction over the claims asserted. The plaintiff has sought review of that dismissal from the Tenth Circuit Court of Appeals, where the matter remains pending.

     In addition, CERC Corp. and certain of its subsidiaries are defendants in two mismeasurement lawsuits brought against approximately 245 pipeline companies and their affiliates pending in state court in Stevens County, Kansas. In one case (originally filed in May 1999 and amended four times), the plaintiffs purport to represent a class of royalty owners who allege that the defendants have engaged in systematic mismeasurement of the volume of natural gas for more than 25 years. The plaintiffs amended their petition in this suit in July 2003 in response to an order from the judge denying certification of the plaintiffs’ alleged class. In the amendment the plaintiffs dismissed their claims against certain defendants (including two CERC Corp. subsidiaries), limited the scope of the class of plaintiffs they purport to represent and eliminated previously asserted claims based on mismeasurement of the British thermal unit (Btu) content of the gas. The same plaintiffs then filed a second lawsuit, again as representatives of a putative class of royalty owners, in which they assert their claims that the defendants have engaged in systematic mismeasurement of the Btu content of natural gas for more than 25 years. In both lawsuits, the plaintiffs seek compensatory damages, along with statutory penalties, treble damages, interest, costs and fees. The Company believes that there has been no systematic mismeasurement of gas and that the lawsuits are without merit. The Company does not expect the ultimate outcome of the lawsuits to have a material impact on its financial condition, results of operations or cash flows.

     Gas Cost Recovery Litigation.  In October 2002, the Company’s ratepayers filed suit in state district court in Wharton County, Texas against the Company, CenterPoint Energy, Entex Gas Marketing Company (EGMC), and certain non-affiliated companies alleging fraud, violations of the Texas Deceptive Trade Practices Act, violations of the Texas Utilities Code, civil conspiracy and violations of the Texas Free Enterprise and Antitrust Act with respect to rates charged to certain consumers of natural gas in the State of Texas. The plaintiffs initially sought certification of a class of Texas ratepayers, but subsequently dropped their request for class certification. The plaintiffs later added as defendants CenterPoint Energy Marketing Inc., CenterPoint Energy Gas Transmission Company (CEGT), United Gas, Inc., Louisiana Unit Gas Transmission Company, CenterPoint Energy Pipeline Services, Inc. (CEPS), and CenterPoint Energy Trading and Transportation Group, Inc., all of which are subsidiaries of the Company, and other non-affiliated companies. In February 2005, the case was removed to federal district court in Houston, Texas, and in March 2005, the plaintiffs voluntarily dismissed the case and agreed not to refile the claims asserted unless the Miller County case described below is not certified as a class action or is later decertified.

     In October 2004, the Company’s ratepayers in Texas and Arkansas filed suit in circuit court in Miller County, Arkansas against the Company, CenterPoint Energy, EGMC, CEGT, CenterPoint Energy Field Services (CEFS), CEPS, Mississippi River Transmission Corp. (MRT) and other non-affiliated companies alleging fraud, unjust enrichment and civil conspiracy with respect to rates charged to certain consumers of natural gas in Arkansas, Louisiana, Minnesota, Mississippi, Oklahoma and Texas. Subsequently, the plaintiffs dropped as defendants CEGT and MRT. The plaintiffs seek class certification, but the proposed class has not been certified. In June 2007, the Arkansas Supreme Court determined that the Arkansas claims are within the sole and exclusive jurisdiction of the APSC. Also in June 2007, the Company, CenterPoint Energy, EGMC and other defendants in the Miller County case filed a petition in a district court in Travis County, Texas seeking a determination that the Railroad Commission has original exclusive jurisdiction over the Texas claims asserted in the Miller County case. In August 2007 the Miller County court stayed but refused to dismiss the Arkansas claims. Also in August 2007, the Arkansas plaintiff initiated a complaint at the APSC seeking a decision concerning the extent of the APSC’s jurisdiction over the Miller County case and an investigation into the merits of the allegations asserted in his complaint with respect to the Company. In September 2007, the Company, CenterPoint Energy, EGMC and other defendants in the Miller County case initiated proceedings in the Arkansas Supreme Court to direct the Miller County court to dismiss the

entire case on the grounds that the plaintiffs’ claims are within the exclusive jurisdiction of the APSC or Railroad Commission, as applicable.

     In February 2003, a lawsuit was filed in state court in Caddo Parish, Louisiana against the Company with respect to rates charged to a purported class of certain consumers of natural gas and gas service in the State of Louisiana. In February 2004, another suit was filed in state court in Calcasieu Parish, Louisiana against the Company seeking to recover alleged overcharges for gas or gas services allegedly provided by the Company to a purported class of certain consumers of natural gas and gas service without advance approval by the Louisiana Public Service Commission (LPSC). At the time of the filing of each of the Caddo and Calcasieu Parish cases, the plaintiffs in those cases filed petitions with the LPSC relating to the same alleged rate overcharges. The Caddo and Calcasieu Parish cases have been stayed pending the resolution of the proceedings by the LPSC.  In August 2007, the LPSC issued an order approving a Stipulated Settlement in the review initiated by the plaintiffs in the Calcasieu Parish litigation.  In that proceeding, the Company’s gas purchases were reviewed back to 1971.  The review concluded that the Company’s gas costs were “reasonable and prudent”, but the Company agreed to credit to jurisdictional customers approximately $920,000 related to certain off-system sales, including interest.  A regulatory liability was established and the Company began refunding that amount to jurisdictional customers in September 2007.  A similar review related to the Caddo Parish litigation remains pending at the LPSC.

     The range of relief sought by the plaintiffs in the Caddo Parish case includes injunctive and declaratory relief, restitution for the alleged overcharges, exemplary damages or trebling of actual damages, civil penalties and attorney’s fees. In this case, the Company, CenterPoint Energy and their affiliates deny that they have overcharged any of their customers for natural gas and believe that the amounts recovered for purchased gas have been in accordance with what is permitted by state and municipal regulatory authorities. The Company does not expect the outcome of this matter to have a material impact on its financial condition, results of operations or cash flows.

     Storage Facility Litigation.  In February 2007, an Oklahoma district court in Coal County, Oklahoma, granted a summary judgment against CEGT in a case, Deka Exploration, Inc. v. CenterPoint Energy, filed by holders of oil and gas leaseholds and some mineral interest owners in lands underlying CEGT’s Chiles Dome Storage Facility. The dispute concerns “native gas” that may have been in the Wapanucka formation underlying the Chiles Dome facility when that facility was constructed in 1979 by a Company entity that was the predecessor in interest of CEGT. The court ruled that the plaintiffs own native gas underlying those lands, since neither CEGT nor its predecessors had condemned those ownership interests. The court rejected CEGT’s contention that the claim should be barred by the statute of limitations, since suit was filed over 25 years after the facility was constructed. The court also rejected CEGT’s contention that the suit is an impermissible attack on the determinations the FERC and Oklahoma Corporation Commission made regarding the absence of native gas in the lands when the facility was constructed. The summary judgment ruling was only on the issue of liability, though the court did rule that CEGT has the burden of proving that any gas in the Wapanucka formation is gas that has been injected and is not native gas. Further hearings and orders of the court are required to specify the appropriate relief for the plaintiffs. CEGT plans to appeal through the Oklahoma court system any judgment which imposes liability on CEGT in this matter. The Company does not expect the outcome of this matter to have a material impact on its financial condition, results of operations or cash flows.

Environmental Matters

     Hydrocarbon Contamination.  CERC Corp. and certain of its subsidiaries were among the defendants in lawsuits filed beginning in August 2001 in Caddo Parish and Bossier Parish, Louisiana. The suits alleged that, at some unspecified date prior to 1985, the defendants allowed or caused hydrocarbon or chemical contamination of the Wilcox Aquifer, which lies beneath property owned or leased by certain of the defendants and which is the sole or primary drinking water aquifer in the area. The primary source of the contamination was alleged by the plaintiffs to be a gas processing facility in Haughton, Bossier Parish, Louisiana known as the “Sligo Facility,” which was formerly operated by a predecessor in interest of CERC Corp. This facility was purportedly used for gathering natural gas from surrounding wells, separating liquid hydrocarbons from the natural gas for marketing, and transmission of natural gas for distribution.

     In July 2007, pursuant to the terms of a previously agreed settlement in principle, the parties implemented the terms of their settlement and resolved this matter. Pursuant to the agreed terms, a CERC Corp. subsidiary had entered into a cooperative agreement with the Louisiana Department of Environmental Quality (LDEQ), pursuant to which CERC Corp.’s subsidiary will work with the LDEQ to develop a remediation plan that could be implemented by the CERC Corp. subsidiary. Pursuant to the settlement terms, the Company made a settlement payment within

the amounts previously reserved for this matter. The Company does not expect the costs associated with the resolution of this matter to have a material impact on its financial condition, results of operations or cash flows.

     Manufactured Gas Plant Sites.  The Company and its predecessors operated manufactured gas plants (MGP) in the past. In Minnesota, the Company has completed remediation on two sites, other than ongoing monitoring and water treatment. There are five remaining sites in the Company’s Minnesota service territory. The Company believes that it has no liability with respect to two of these sites.

     At September 30, 2007, the Company had accrued $14 million for remediation of these Minnesota sites and the estimated range of possible remediation costs for these sites was $4 million to $35 million based on remediation continuing for 30 to 50 years. The cost estimates are based on studies of a site or industry average costs for remediation of sites of similar size. The actual remediation costs will be dependent upon the number of sites to be remediated, the participation of other potentially responsible parties (PRP), if any, and the remediation methods used. The Company has utilized an environmental expense tracker mechanism in its rates in Minnesota to recover estimated costs in excess of insurance recovery. As of September 30, 2007, the Company had collected $13 million from insurance companies and rate payers to be used for future environmental remediation.

     In addition to the Minnesota sites, the United States Environmental Protection Agency and other regulators have investigated MGP sites that were owned or operated by the Company or may have been owned by one of its former affiliates. The Company has been named as a defendant in a lawsuit filed in the United States District Court, District of Maine, under which contribution is sought by private parties for the cost to remediate former MGP sites based on the previous ownership of such sites by former affiliates of the Company or its divisions. The Company has also been identified as a PRP by the State of Maine for a site that is the subject of the lawsuit. In June 2006, the federal district court in Maine ruled that the current owner of the site is responsible for site remediation but that an additional evidentiary hearing is required to determine if other potentially responsible parties, including the Company, would have to contribute to that remediation. The Company is investigating details regarding the site and the range of environmental expenditures for potential remediation. However, the Company believes it is not liable as a former owner or operator of the site under the Comprehensive Environmental, Response, Compensation and Liability Act of 1980, as amended, and applicable state statutes, and is vigorously contesting those suits and its designation as a PRP.

     Mercury Contamination.  The Company’s pipeline and distribution operations have in the past employed elemental mercury in measuring and regulating equipment. It is possible that small amounts of mercury may have been spilled in the course of normal maintenance and replacement operations and that these spills may have contaminated the immediate area with elemental mercury. The Company has found this type of contamination at some sites in the past, and the Company has conducted remediation at these sites. It is possible that other contaminated sites may exist and that remediation costs may be incurred for these sites. Although the total amount of these costs is not known at this time, based on the Company’s experience and that of others in the natural gas industry to date and on the current regulations regarding remediation of these sites, the Company believes that the costs of any remediation of these sites will not be material to the Company’s financial condition, results of operations or cash flows.

     Asbestos.  Some facilities formerly owned by the Company’s predecessors have contained asbestos insulation and other asbestos-containing materials. The Company or its predecessor companies have been named, along with numerous others, as a defendant in lawsuits filed by certain individuals who claim injury due to exposure to asbestos during work at such formerly owned facilities. The Company anticipates that additional claims like those received may be asserted in the future. Although their ultimate outcome cannot be predicted at this time, the Company intends to continue vigorously contesting claims that it does not consider to have merit and does not expect, based on its experience to date, these matters, either individually or in the aggregate, to have a material adverse effect on the Company’s financial condition, results of operations or cash flows.

     Other Environmental.  From time to time the Company 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, the Company 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, the Company does not expect, based on its experience to date, these matters, either individually or in the aggregate, to have a material adverse effect on the Company’s financial condition, results of operations or cash flows.

Other Proceedings

     The Company 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. Some of these proceedings involve substantial amounts. The Company regularly analyzes current information and, as necessary, provides accruals for probable liabilities on the eventual disposition of these matters. The Company does not expect the disposition of these matters to have a material adverse effect on the Company’s financial condition, results of operations or cash flows.

Guaranties

     Prior to CenterPoint Energy’s distribution of its ownership in Reliant Energy, Inc. (RRI) to its shareholders, the Company had guaranteed certain contractual obligations of what became RRI’s trading subsidiary. Under the terms of the separation agreement between the companies, RRI agreed to extinguish all such guaranty obligations prior to separation, but at the time of separation in September 2002, RRI had been unable to extinguish all obligations. To secure the Company and CenterPoint Energy against obligations under the remaining guaranties, RRI agreed to provide cash or letters of credit for the benefit of the Company and CenterPoint Energy, and undertook to use commercially reasonable efforts to extinguish the remaining guaranties. In February 2007, the Company and CenterPoint Energy made a formal demand on RRI under procedures provided by the Master Separation Agreement, dated as of December 31, 2000, between Reliant Energy and RRI. That demand sought to resolve a disagreement with RRI over the amount of security RRI is obligated to provide with respect to this guaranty. In conjunction with discussion of that demand, CenterPoint Energy and RRI entered into an agreement to delay further proceedings regarding this dispute in order to permit further discussions. The Company currently holds letters of credit in the amount of $29.3 million issued on behalf of RRI against guaranties that have not been released. CenterPoint Energy’s current exposure under the guaranties relates to the Company’s guaranty of the payment by RRI of demand charges related to transportation contracts with one counterparty. RRI has advised the Company and CenterPoint Energy that it has permanently released a portion of the capacity its trading subsidiary holds under those transportation contracts, and the Company has been released from its guaranty with respect to the capacity released.

     In June 2006, the RRI trading subsidiary and the Company jointly filed a complaint with the FERC against the counterparty on the Company’s guaranty. In response to the FERC’s July 2007 order regarding that complaint, the counterparty accepted, with respect to one of the four transportation contracts, the replacement of the Company’s guaranty with a letter of credit provided by RRI in the amount of three months of demand charges. The three remaining transportation contracts continue to be covered by the Company’s guaranty. After giving effect to the assignments and the substitution of the RRI letter of credit, the reduced level of demand charges is now approximately $19 million per year in 2008, $18 million in 2009 through 2015, $17 million in 2016, $10 million in 2017 and $3 million in 2018. RRI continues to meet its obligations under the transportation contracts, and the Company believes current market conditions make those contracts valuable for transportation services in the near term and that additional security is not needed at this time. However, changes in market conditions could affect the value of those contracts. If RRI should fail to perform its obligations under the transportation contracts, CenterPoint Energy’s exposure to the counterparty under the guaranty could exceed the security provided by RRI.

(11) Income Taxes

     The following table summarizes the Company’s liability (receivable) for uncertain tax positions in accordance with FIN 48 at January 1 and September 30, 2007 (in millions):

		January 1,				September 30,
		2007				2007
Liability (receivable) for uncertain tax positions		$	0.7			$	(5.4	)
Portion of liability for uncertain tax positions that, if recognized, would reduce the effective income tax rate			9.0				1.4
Interest accrued on uncertain tax positions			1.3				(2.2	)

(12) Reportable Business Segments

     Because the Company is an indirect wholly owned subsidiary of CenterPoint Energy, the Company’s determination of reportable business segments considers the strategic operating units under which CenterPoint Energy manages sales, allocates resources and assesses performance of various products and services to wholesale or retail customers in differing regulatory environments. The accounting policies of the business segments are the

same as those described in the summary of significant accounting policies except that some executive benefit costs have not been allocated to business segments. The Company uses operating income as the measure of profit or loss for its business segments.

     The Company’s reportable business segments include the following: Natural Gas Distribution, Competitive Natural Gas Sales and Services, Interstate Pipelines, Field Services 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. Competitive Natural Gas Sales and Services represents the Company’s non-rate regulated gas sales and services operations, which consist of three operational functions: wholesale, retail and intrastate pipelines. Beginning in the fourth quarter of 2006, the Company began reporting its interstate pipelines and field services businesses as two separate business segments, the Interstate Pipelines business segment and the Field Services business segment. These business segments were previously aggregated and reported as the Pipelines and Field Services business segment. The Interstate Pipelines business segment includes the interstate natural gas pipeline operations. The Field Services business segment includes the natural gas gathering and processing operations. Other Operations consists primarily of other corporate operations which support all of the Company’s business operations. All prior periods have been recast to conform to the 2007 presentation.

     Long-lived assets include net property, plant and equipment, net goodwill and equity investments in unconsolidated subsidiaries. Intersegment sales are eliminated in consolidation.

     Financial data for business segments and products and services are as follows (in millions):

		For the Three Months Ended September 30, 2006
		Revenues from				Net
		External				Intersegment				Operating
		Customers				Revenues				Income (Loss)
Natural Gas Distribution		$	483			$	2			$	(11	)
Competitive Natural Gas Sales and Services			813				17				12
Interstate Pipelines			73				33				48
Field Services			31				8				21
Other Operations			—				—				(1	)
Eliminations			—				(60	)			—
Consolidated		$	1,400			$	—			$	69

		For the Three Months Ended September 30, 2007
		Revenues from				Net
		External				Intersegment				Operating
		Customers				Revenues				Income (Loss)
Natural Gas Distribution		$	457			$	1			$	(8	)
Competitive Natural Gas Sales and Services			758				12				4
Interstate Pipelines			100				37				70
Field Services			36				8				26
Other Operations			—				—				(1	)
Eliminations			—				(58	)			—
Consolidated		$	1,351			$	—			$	91

		For the Nine Months Ended September 30, 2006
		Revenues from				Net								Total Assets
		External				Intersegment				Operating				as of
		Customers				Revenues				Income (Loss)				December 31, 2006
Natural Gas Distribution		$	2,506			$	8			$	90			$	4,463
Competitive Natural Gas Sales and Services			2,681				62				44				1,501
Interstate Pipelines			198				101				137				2,738
Field Services			89				25				66				608
Other Operations			—				4				(3	)			1,086
Eliminations			—				(200	)			—				(1,581	)
Consolidated		$	5,474			$	—			$	334			$	8,815

		For the Nine Months Ended September 30, 2007
		Revenues from				Net								Total Assets
		External				Intersegment				Operating				as of
		Customers				Revenues				Income (Loss)				September 30, 2007
Natural Gas Distribution		$	2,594			$	7			$	129			$	4,199
Competitive Natural Gas Sales and Services			2,679				36				56				1,154
Interstate Pipelines			247				101				166				2,934
Field Services			94				31				75				642
Other Operations			—				—				(2	)			453
Eliminations			—				(175	)			—				(883	)
Consolidated		$	5,614			$	—			$	424			$	8,499

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

     The following narrative analysis should be read in combination with our Interim Condensed Financial Statements contained in Item 1 of this report.

     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, 2006 and the three and nine months ended September 30, 2007. Reference is made to “Management’s Narrative Analysis of the Results of Operations” in Item 7 of the Annual Report on Form 10-K of CERC Corp. for the year ended December 31, 2006 (CERC Corp. Form 10-K).

EXECUTIVE SUMMARY

Recent Events

   Debt Financing Transactions

     In October 2007, we issued $250 million aggregate principal amount of 6.125% senior notes due in November 2017 and $250 million aggregate principal amount of 6.625% senior notes due in November 2037. The proceeds from the sale of the senior notes will be used for general corporate purposes, including repayment or refinancing of debt, including $300 million of our 6.5% senior notes due February 1, 2008, capital expenditures, working capital and loans to or investments in affiliates. Pending application of the proceeds for these purposes, we repaid borrowings under our revolving credit and receivables facilities.

     In October 2007, we amended our receivables facility and extended the termination date to October 28, 2008. The facility size will range from $150 million to $375 million during the period from September 30, 2007 to the October 28, 2008 termination date. The variable size of the facility was designed to track the seasonal pattern of receivables in our natural gas businesses.

Interstate Pipeline Expansion

     Carthage to Perryville. In April 2007, CenterPoint Energy Gas Transmission (CEGT), our wholly owned subsidiary, completed phase one construction of a 172-mile, 42-inch diameter pipeline and related compression facilities for the transportation of gas from Carthage, Texas to CEGT’s Perryville hub in Northeast Louisiana.  On May 1, 2007, CEGT began service under its firm transportation agreements with shippers of approximately 960 million cubic feet per day. CEGT’s second phase of the project, which involved adding compression that increased the total capacity of the pipeline to approximately 1.25 billion cubic feet (Bcf) per day, was placed into service in August 2007. CEGT has signed firm contracts for the full capacity of phases one and two.

     Based on interest expressed during an open season held in 2006, CEGT will add a phase three which will expand capacity of the pipeline to 1.5 Bcf per day by adding additional compression and operating at higher pressures. In May 2007, CEGT received Federal Energy Regulatory Commission (FERC) approval for the third phase of the project to expand capacity of the pipeline, and in July 2007, CEGT received U.S. Department of Transportation approval to increase the maximum allowable operating pressure. The third phase is projected to be in-service in the first quarter of 2008.

     Southeast Supply Header.   In June 2006, CenterPoint Energy Southeast Pipelines Holding, L.L.C., our wholly owned subsidiary, and a subsidiary of Spectra Energy Corp. (Spectra) formed a joint venture (Southeast Supply Header or SESH) to construct, own and operate a 270-mile pipeline with a capacity of approximately 1 Bcf per day that will extend from CEGT’s Perryville hub in northeast Louisiana to a point interconnecting with Gulfstream Natural Gas System, which is 50 percent owned by an affiliate of Spectra. We account for our 50 percent interest in SESH as an equity investment. In 2006, SESH signed agreements with shippers for firm transportation services, which subscribed capacity of 945 million cubic feet per day.

     An application to construct, own and operate the pipeline was filed with the FERC in December 2006. In September 2007, the FERC issued the certificate authorizing the construction of the pipeline. SESH is currently in the preliminary construction stage and is updating its projection for capital costs for the pipeline. Based on a preliminary analysis, SESH is currently projecting the capital costs for its interest in the pipeline may exceed $900 million. SESH expects to complete construction in the summer of 2008.

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. 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, 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 the CERC Corp. Form 10-K and “Risk Factors” in Item 1A of Part II of this Quarterly Report on Form 10-Q.

     The following table sets forth our consolidated results of operations for the three and nine months ended September 30, 2006 and 2007, followed by a discussion of the results of operations by business segment based on operating income.

		Three Months Ended September 30,								Nine Months Ended September 30,
		2006				2007				2006				2007
						(in millions)
Revenues		$	1,400			$	1,351			$	5,474			$	5,614
Expenses:
Natural gas			1,058				990				4,286				4,348
Operation and maintenance			192				191				588				577
Depreciation and amortization			50				56				150				159
Taxes other than income taxes			31				23				116				106
Total Expenses			1,331				1,260				5,140				5,190
Operating Income			69				91				334				424
Interest and Other Finance Charges			(43	)			(51	)			(125	)			(135	)
Other Income, net			7				7				15				14
Income Before Income Taxes			33				47				224				303
Income Tax Expense			(20	)			(19	)			(91	)			(114	)
Net Income		$	13			$	28			$	133			$	189

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, 2006 and 2007. Due to the change in reportable segments in the fourth quarter of 2006, we have recast our segment information for 2006, as discussed in Note 12 to our Interim Condensed Financial Statements, to conform to the new presentation. The segment detail revised as a result of the new reportable business segments did not affect consolidated operating income for any period.

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2006				2007				2006				2007
						(in millions)
Natural Gas Distribution		$	(11	)		$	(8	)		$	90			$	129
Competitive Natural Gas Sales and Services			12				4				44				56
Interstate Pipelines			48				70				137				166
Field Services			21				26				66				75
Other Operations			(1	)			(1	)			(3	)			(2	)
Total Consolidated Operating Income		$	69			$	91			$	334			$	424

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 Affecting Our Natural Gas Distribution, Competitive Natural Gas Sales and Services, Interstate Pipelines and Field Services Businesses,” “— Risk Factors Associated with Our Consolidated Financial Condition” and “— Risks Common to Our Business and Other Risks” in Item 1A of Part I of the CERC Corp. Form 10-K and “Risk Factors” in Item 1A of Part II of this Quarterly Report on Form 10-Q.

     The following table provides summary data of our Natural Gas Distribution business segment for the three and nine months ended September 30, 2006 and 2007 (in millions, except throughput and customer data):

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2006				2007				2006				2007
Revenues		$	485			$	458			$	2,514			$	2,601
Expenses:
Natural gas			298				267				1,787				1,845
Operation and maintenance			137				139				429				421
Depreciation and amortization			38				38				113				114
Taxes other than income taxes			23				22				95				92
Total expenses			496				466				2,424				2,472
Operating Income (Loss)		$	(11	)		$	(8	)		$	90			$	129
Throughput (in Bcf):
Residential			14				12				98				118
Commercial and industrial			44				42				160				168
Total Throughput			58				54				258				286
Average number of customers:
Residential			2,862,020				2,910,041				2,875,345				2,927,122
Commercial and industrial			240,083				246,021				243,011				246,382
Total			3,102,103				3,156,062				3,118,356				3,173,504

Three months ended September 30, 2007 compared to three months ended September 30, 2006

     Our Natural Gas Distribution business segment reported an operating loss of $8 million for the three months ended September 30, 2007 compared to an operating loss of $11 million for the three months ended September 30, 2006. Operating income improved as a result of customer growth ($2 million) from the addition of nearly 48,000 customers since September 30, 2006.

Nine months ended September 30, 2007 compared to nine months ended September 30, 2006

     Our Natural Gas Distribution business segment reported operating income of $129 million for the nine months ended September 30, 2007 compared to operating income of $90 million for the nine months ended September 30, 2006. Operating income improved as a result of increased usage primarily due to unusually mild weather in 2006 ($14 million) and growth from the addition of nearly 48,000 customers since September 30, 2006 ($7 million) and reduced operation and maintenance expenses, primarily as a result of costs associated with staff reductions incurred in 2006 ($15 million), reduced employee benefit costs ($9 million) and the 2006 write-off of certain rate case expenses ($3 million). The increase in operating income was partially offset by higher expenses associated with initiatives undertaken to improve customer service ($4 million) and the recognition in 2006 of certain favorable regulatory orders ($4 million).

Competitive Natural Gas Sales and Services

     For information regarding factors that may affect the future results of operations of our Competitive Natural Gas Sales and Services business segment, please read “Risk Factors — Risk Factors Affecting Our Natural Gas Distribution, Competitive Natural Gas Sales and Services, Interstate Pipelines and Field Services Business,” “— Risk Factors Associated with Our Consolidated Financial Condition” and “— Risks Common to Our Business and Other Risks” in Item 1A of Part I of the CERC Corp. Form 10-K and “Risk Factors” in Item 1A of Part II of this Quarterly Report on Form 10-Q.

     The following table provides summary data of our Competitive Natural Gas Sales and Services business segment for the three and nine months ended September 30, 2006 and 2007 (in millions, except throughput and customer data):

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2006				2007				2006				2007
Revenues		$	830			$	770			$	2,743			$	2,715
Expenses:
Natural gas			809				756				2,673				2,631
Operation and maintenance			8				7				23				23
Depreciation and amortization			—				3				1				4
Taxes other than income taxes			1				—				2				1
Total expenses			818				766				2,699				2,659
Operating Income		$	12			$	4			$	44			$	56
Throughput (in Bcf):
Wholesale – third parties			90				74				251				241
Wholesale – affiliates			8				2				27				7
Retail and Pipeline			40				43				138				145
Total Throughput			138				119				416				393
Average number of customers:
Wholesale			140				233				140				235
Retail and Pipeline			6,351				6,743				6,554				6,779
Total			6,491				6,976				6,694				7,014

Three months ended September 30, 2007 compared to three months ended September 30, 2006

     Our Competitive Natural Gas Sales and Services business segment reported operating income of $4 million for the three months ended September 30, 2007 compared to operating income of $12 million for the three months ended September 30, 2006. The decrease in operating income of $8 million was primarily due to a reduction in locational and seasonal natural gas price differentials ($4 million). In addition, the third quarter of 2007 included a gain from mark-to-market accounting for non-trading financial derivatives ($2 million) and a write-down of natural gas inventory to the lower of average cost or market ($5 million), compared to a gain from mark-to-market accounting ($21 million) and a natural gas inventory write-down ($26 million) for the same period of 2006. Natural gas that is purchased for inventory is accounted for at the lower of average cost or market price at each balance sheet date.

Nine months ended September 30, 2007 compared to nine months ended September 30, 2006

     Our Competitive Natural Gas Sales and Services business segment reported operating income of $56 million for the nine months ended September 30, 2007 compared to $44 million for the nine months ended September 30, 2006. The increase in operating income of $12 million was primarily due to increased operating margins (revenues less natural gas costs) related to sales of gas from inventory and asset utilization. In addition, the first nine months of 2007 included a charge from mark-to-market accounting for non-trading financial derivatives ($12 million) and a write-down of natural gas inventory to the lower of average cost or market ($11 million), compared to a gain from mark-to-market accounting ($34 million) and an inventory write-down ($56 million) for the same period of 2006.

Interstate Pipelines

     For information regarding factors that may affect the future results of operations of our Interstate Pipelines business segment, please read “Risk Factors — Risk Factors Affecting Our Natural Gas Distribution, Competitive Natural Gas Sales and Services, Interstate Pipelines and Field Services Businesses,” “— Risk Factors Associated with Our Consolidated Financial Condition” and “— Risks Common to Our Business and Other Risks” in Item 1A of Part I of the CERC Corp. Form 10-K and “Risk Factors” in Item 1A of Part II of this Quarterly Report on Form 10-Q.

     The following table provides summary data of our Interstate Pipelines business segment for the three and nine months ended September 30, 2006 and 2007 (in millions, except throughput data):

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2006				2007				2006				2007
Revenues		$	106			$	137			$	299			$	348
Expenses:
Natural gas			10				27				22				55
Operation and maintenance			33				29				98				85
Depreciation and amortization			10				11				28				32
Taxes other than income taxes			5				—				14				10
Total expenses			58				67				162				182
Operating Income		$	48			$	70			$	137			$	166
Throughput (in Bcf):
Transportation			204				312				718				880

Three months ended September 30, 2007 compared to three months ended September 30, 2006

     Our Interstate Pipeline business segment reported operating income of $70 million for the three months ended September 30, 2007 compared to $48 million for the three months ended September 30, 2006. The increase in operating income was primarily due to the new Carthage to Perryville pipeline ($16 million) and other transportation and ancillary services ($11 million). Additionally, taxes other than income were lower than 2006 primarily due to tax refunds ($4 million) related to the settlement of certain state tax issues. These favorable variances were partially offset by the FERC-authorized sale of excess gas associated with our storage enhancement projects ($13 million) in the third quarter of 2006.

Nine months ended September 30, 2007 compared to nine months ended September 30, 2006

     Our Interstate Pipeline business segment reported operating income of $166 million for the nine months ended September 30, 2007 compared to $137 million for the nine months ended September 30, 2006. The increase in operating income was primarily due to the new Carthage to Perryville pipeline, which went into commercial service in May 2007 ($25 million), other transportation and ancillary services ($17 million) and lower taxes other than income ($4 million) as discussed previously. These favorable variances were partially offset by higher sales in 2006 of excess gas associated with storage enhancement projects ($10 million) and the absence of a favorable storage adjustment recorded in the first quarter of 2006 ($3 million).

Field Services

     For information regarding factors that may affect the future results of operations of our Field Services business segment, please read “Risk Factors — Risk Factors Affecting Our Natural Gas Distribution, Competitive Natural Gas Sales and Services, Interstate Pipelines and Field Services Businesses,” “— Risk Factors Associated with Our Consolidated Financial Condition” and “— Risks Common to Our Business and Other Risks” in Item 1A of Part I of the CERC Corp. Form 10-K and “Risk Factors” in Item 1A of Part II of this Quarterly Report on Form 10-Q.

     The following table provides summary data of our Field Services business segment for the three and nine months ended September 30, 2006 and 2007 (in millions, except throughput data):

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2006				2007				2006				2007
Revenues		$	39			$	44			$	114			$	125
Expenses:
Natural gas			(1	)			(2	)			(4	)			(9	)
Operation and maintenance			15				17				42				49
Depreciation and amortization			3				2				8				8
Taxes other than income taxes			1				1				2				2
Total expenses			18				18				48				50
Operating Income		$	21			$	26			$	66			$	75
Throughput (in Bcf):
Gathering			97				104				279				297

Three months ended September 30, 2007 compared to three months ended September 30, 2006

     Our Field Services business segment reported operating income of $26 million for the three months ended September 30, 2007 compared to $21 million for the three months ended September 30, 2006. Increased revenues due to higher throughput and ancillary services ($9 million) was partially offset by lower commodity prices ($2 million) and increased operation and maintenance expenses related to cost increases and expanded operations ($2 million).

     In addition, this business segment recorded equity income of $2 million in each of the three months ended September 30, 2006 and 2007 from its 50 percent interest in the Waskom plant. These amounts are included in Other – net under the Other Income (Expense) caption.

Nine months ended September 30, 2007 compared to nine months ended September 30, 2006

     Our Field Services business segment reported operating income of $75 million for the nine months ended September 30, 2007 compared to $66 million for the nine months ended September 30, 2006. Continued increased demand for gas gathering and ancillary services ($25 million) was partially offset by lower commodity prices ($9 million) and increased operation and maintenance expenses related to cost increases and expanded operations ($7 million).

     In addition, this business segment recorded equity income of $7 million and $6 million in the nine months ended September 30, 2006 and 2007, respectively, from its 50 percent interest in the Waskom plant. These amounts are included in Other – net under the Other Income (Expense) caption.

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 and “Management’s Narrative Analysis of Results of Operations — Certain Factors Affecting Future Earnings” in Item 7 of Part II of the CERC Corp. Form 10-K, “Risk Factors” in Item 1A of Part II of this Quarterly Report on Form 10-Q and “Cautionary Statement Regarding Forward-Looking Information.”

LIQUIDITY AND CAPITAL RESOURCES

          Our liquidity and capital requirements are affected primarily by our results of operations, capital expenditures, debt service requirements, and working capital needs. Our principal cash requirements for the remaining three months of 2007 are approximately $240 million of capital expenditures and investment in or advances to SESH of approximately $120 million.

          We expect that borrowings under our credit facility, anticipated cash flows from operations and borrowings from affiliates will be sufficient to meet our cash needs for the remaining three months of 2007. Cash needs or discretionary financing or refinancing may also result in the issuance of debt securities in the capital markets.

          Arkansas Public Service Commission (APSC), Affiliate Transaction Rulemaking Proceeding.  In December 2006, the APSC adopted new rules governing affiliate transactions involving public utilities operating in Arkansas. In February 2007, in response to requests by us and other gas and electric utilities operating in Arkansas, the APSC granted reconsideration of the rules and stayed their operation in order to permit additional consideration. In May 2007, the APSC adopted revised rules, which incorporated many revisions proposed by the utilities, the Arkansas Attorney General and the APSC staff. The revised rules prohibit affiliated financing transactions for purposes not related to utility operations, but permit the continuation of existing money pool and multi-jurisdictional financing arrangements such as those we currently have in place. Non-financial affiliate transactions generally have to be priced under an asymmetrical pricing formula under which utilities would benefit from any difference between the cost of providing goods and services to or from the utility operations and the market value of those goods or services. However, corporate services provided at fully allocated cost such as those provided by service companies are exempt. The rules also restrict utilities from engaging in businesses other than utility and utility-related businesses if the total book value of non-utility businesses exceeds 10 percent of the book value of the utility and its affiliates. However, existing businesses are grandfathered under the revised rules. The revised rules also permit utilities to petition for waivers of financing and non-financial rules that would otherwise be applicable to their transactions.

          The APSC’s revised rules impose record keeping, record access, employee training and reporting requirements related to affiliate transactions, including notification to the APSC of the formation of new affiliates that will engage in transactions with the utility and annual certification by the utility’s president or chief executive officer and its chief financial officer of compliance with the rules. In addition, the revised rules require a report to the APSC in the event the utility’s bond rating is downgraded in certain circumstances. Although the revised rules impose new requirements on our operations in Arkansas, at this time we do not anticipate that the revised rules will have an adverse effect on existing operations in Arkansas. In September 2007, Gas Operations made a filing with the APSC in accordance with the revised rules to document existing practices that would be covered by grandfathering provisions of those rules.

     Off-Balance Sheet Arrangements.  Other than operating leases and the guaranties described below, we have no off-balance sheet arrangements.

          Prior to CenterPoint Energy’s distribution of its ownership in Reliant Energy, Inc. (RRI) to its shareholders, we had guaranteed certain contractual obligations of what became RRI’s trading subsidiary. Under the terms of the separation agreement between the companies, RRI agreed to extinguish all such guaranty obligations prior to separation, but at the time of separation in September 2002, RRI had been unable to extinguish all obligations. To secure us and CenterPoint Energy against obligations under the remaining guaranties, RRI agreed to provide cash or letters of credit for our benefit and that of CenterPoint Energy, and undertook to use commercially reasonable efforts to extinguish the remaining guaranties. In February 2007, we and CenterPoint Energy made a formal demand on RRI under procedures provided by the Master Separation Agreement, dated as of December 31, 2000, between Reliant Energy, Incorporated (Reliant Energy) and RRI. That demand sought to resolve a disagreement with RRI over the amount of security RRI is obligated to provide with respect to this guaranty. In conjunction with discussion of that demand, we and RRI entered into an agreement to delay further proceedings regarding this dispute in order to permit further discussions. We currently hold letters of credit in the amount of $29.3 million issued on behalf of RRI against guaranties that have not been released. CenterPoint Energy’s current exposure under the guaranties relates to our guaranty of the payment by RRI of demand charges related to transportation contracts with one counterparty. RRI has advised us and CenterPoint Energy that it has permanently released a portion of the capacity its trading subsidiary holds under those transportation contracts, and we have been released from our guaranty with respect to the capacity released.

          In June 2006, we and the RRI trading subsidiary jointly filed a complaint with the FERC against the counterparty on our guaranty. In response to the FERC’s July 2007 order regarding that complaint, the counterparty accepted, with respect to one of the four transportation contracts, the replacement of our guaranty with a letter of credit provided by RRI in the amount of three months of demand charges. The three remaining transportation contracts continue to be covered by our guaranty. After giving effect to the assignments and the substitution of the RRI letter of credit, the reduced level of demand charges is now approximately $19 million per year in 2008, $18 million in 2009 through 2015, $17 million in 2016, $10 million in 2017 and $3 million in 2018. RRI continues to meet its obligations under the transportation contracts, and we believe current market conditions make those contracts valuable for transportation services in the near term and that additional security is not needed at this time. However, changes in market conditions could affect the value of those contracts. If RRI should fail to perform its obligations under the transportation contracts, CenterPoint Energy's exposure to the counterparty under the guaranty could exceed the security provided by RRI.

     Credit and Receivables Facilities.  In June 2007, we entered into an amended and restated bank credit facility. Our amended credit facility is a $950 million five-year senior unsecured revolving credit facility versus a $550 million facility prior to the amendment. The facility’s first drawn cost remains at the London Interbank Offered Rate (LIBOR) plus 45 basis points based on our current credit ratings. The facility contains covenants, including a debt to total capitalization covenant.

     As of October 31, 2007, we had the following facilities (in millions):

Amount Utilized at

Date Executed

Company

Type of Facility

Size of Facility

October 31, 2007

Termination Date

June 29, 2007

CERC Corp.

Revolver

$

950

$

19

(1)

June 29, 2012

October 30, 2007

CERC

Receivables

200

156

October 28, 2008

     Under our credit facility, an additional utilization fee of 5 basis points applies to borrowings any time more than 50% of the facility is utilized. The spread to LIBOR and the utilization fee fluctuate based on our credit rating. Borrowings under our 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 each of the credit facilities are subject to acceleration upon the occurrence of events of default that we consider customary.

     Our receivables facility terminates in October 2008. The facility size will range from $150 million to $375 million during the period from September 30, 2007 to the October 28, 2008 termination date of the facility. At September 30, 2007, the $150 million facility was fully utilized.

     We are currently in compliance with the various business and financial covenants contained in the respective receivables and credit facilities.

     Securities Registered with the SEC. As of September 30, 2007, we had a shelf registration statement covering $900 million principal amount of senior debt securities. In October 2007, we issued $500 million aggregate principal amount of senior debt securities, resulting in $400 million of capacity remaining on the shelf registration statement.

     Temporary Investments.  As of October 31, 2007, we had external temporary investments of $7 million.

     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 under CenterPoint Energy’s revolving credit facility or the sale of CenterPoint Energy’s commercial paper. At October 31, 2007, we had investments in the money pool of $9 million. The money pool may not provide sufficient funds to meet our cash needs.

     Impact on Liquidity of a Downgrade in Credit Ratings. As of October 31, 2007, Moody’s Investors Service, Inc. (Moody’s), Standard & Poor’s Ratings Services, a division of The McGraw-Hill Companies (S&P) and Fitch, Inc. (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)
Baa3		Stable		BBB		Positive		BBB		Stable

     We cannot assure you that these ratings 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 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, the willingness of suppliers to extend credit lines to us on an unsecured basis and the execution of our commercial strategies.

     A decline in credit ratings could increase borrowing costs under our $950 million revolving credit facility. 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. Additionally, a decline in credit ratings could increase cash collateral requirements and reduce earnings of our Natural Gas Distribution and Competitive Natural Gas Sales and Services business segments.

     CenterPoint Energy Services, Inc. (CES), a wholly owned subsidiary of ours operating in our Competitive Natural Gas Sales and Services business segment, provides comprehensive natural gas sales and services primarily to commercial and industrial customers and electric and gas utilities throughout the central and eastern United States. In order to economically hedge its exposure to natural gas prices, CES uses derivatives with provisions standard for the industry, including those pertaining to credit thresholds. Typically, the credit threshold negotiated with each counterparty defines the amount of unsecured credit that such counterparty will extend to CES. To the extent that the credit exposure that a counterparty has to CES at a particular time does not exceed that credit threshold, CES is not obligated to provide collateral. Mark-to-market exposure in excess of the credit threshold is routinely collateralized by CES. As of September 30, 2007, the amount posted as collateral amounted to approximately $64 million. Should our credit ratings (as the credit support provider for CES) fall below certain levels, CES would be required to provide additional collateral on two business days’ notice up to the amount of its previously unsecured credit limit. We estimate that as of September 30, 2007, unsecured credit limits extended to CES by counterparties aggregate $149 million; however, utilized credit capacity is significantly lower. In addition, we and our subsidiaries purchase natural gas under supply agreements that contain an aggregate credit threshold of $100 million based on our S&P Senior Unsecured Long-Term Debt rating of BBB. Upgrades and downgrades from this BBB rating will increase and decrease the aggregate credit threshold accordingly.

     In connection with the development of SESH’s 270-mile pipeline project, we have committed that we will advance funds to the joint venture or cause funds to be advanced for our 50 percent share of the cost to construct the pipeline. We also agreed to provide a letter of credit in an amount up to $400 million for our share of funds that have not been advanced in the event S&P reduces our bond rating below investment grade before we have advanced the required construction funds. However, we are relieved of these commitments (i) to the extent of 50 percent of any borrowing agreements that the joint venture has obtained and maintains for funding the construction of the pipeline and (ii) to the extent we or our subsidiary participating in the joint venture obtains committed borrowing agreements pursuant to which funds may be borrowed and used for the construction of the pipeline. A similar commitment has been provided by the other party to the joint venture. As of September 30, 2007, our subsidiaries have advanced approximately $103 million to SESH, of which $52 million was equity and $51 million was debt.

     Cross Defaults. Under CenterPoint Energy’s revolving credit facility, a payment default on, or a non-payment default that permits acceleration of, any indebtedness exceeding $50 million by us will cause a default. Pursuant to the indenture governing CenterPoint Energy’s senior notes, a payment default by us, in respect of, or an acceleration of, borrowed money and certain other specified types of obligations, in the aggregate principal amount of $50 million will cause a default. As of September 30, 2007, CenterPoint Energy had six series of senior notes outstanding aggregating $1.4 billion in principal amount under this indenture. A default by CenterPoint Energy would not trigger a default under our debt instruments or bank credit facilities.

     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 gas purchases, gas price hedging and gas storage activities of our Natural Gas Distribution and Competitive Natural Gas Sales and Services business segments, particularly given gas price levels and volatility;
	•		acceleration of payment dates on certain gas supply contracts under certain circumstances, as a result of increased gas prices and concentration of natural gas suppliers;
	•		increased costs related to the acquisition of natural gas;
	•		increases in interest expense in connection with debt refinancings and borrowings under credit facilities;
	•		various regulatory actions;
	•		the ability of RRI and its subsidiaries to satisfy their obligations to us or in connection with the contractual arrangement pursuant to which we are a guarantor;
	•		slower customer payments and increased write-offs of receivables due to higher gas prices or changing economic conditions;
	•		the outcome of litigation brought by and against us;
	•		contributions to benefit plans;
	•		restoration costs and revenue losses resulting from natural disasters such as hurricanes; and
	•		various other risks identified in “Risk Factors” in Item 1A of the CERC Corp. Form 10-K and “Risk Factors” in Item 1A of Part II of this Quarterly Report on Form 10-Q.

     Certain Contractual Limits on Our Ability to Issue Securities and Borrow Money. Our bank facility and our receivables facility limit our debt as a percentage of our total capitalization to 65 percent.

     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.

CRITICAL ACCOUNTING POLICIES

     A critical accounting policy is one that is both important to the presentation of our financial condition and results of operations and requires management to make difficult, subjective or complex accounting estimates. An accounting estimate is an approximation made by management of a financial statement element, item or account in the financial statements. Accounting estimates in our historical consolidated financial statements measure the effects of past business transactions or events, or the present status of an asset or liability. The accounting estimates described below require us to make assumptions about matters that are highly uncertain at the time the estimate is made. Additionally, different estimates that we could have used or changes in an accounting estimate that are reasonably likely to occur could have a material impact on the presentation of our financial condition or results of operations. The circumstances that make these judgments difficult, subjective and/or complex have to do with the need to make estimates about the effect of matters that are inherently uncertain. Estimates and assumptions about future events and their effects cannot be predicted with certainty. We base our estimates on historical experience and

on various other assumptions that we believe to be reasonable under the circumstances, the results of which form the basis for making judgments. These estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes. Our significant accounting policies are discussed in Note 2 to the consolidated financial statements of the CERC Corp. Form 10-K. We believe the following accounting policies involve the application of critical accounting estimates. Accordingly, these accounting estimates have been reviewed and discussed with the audit committee of the board of directors of CenterPoint Energy.

Impairment of Long-Lived Assets and Intangibles

     We review the carrying value of our long-lived assets, including goodwill and identifiable intangibles, whenever events or changes in circumstances indicate that such carrying values may not be recoverable, and at least annually for goodwill as required by SFAS No. 142, “Goodwill and Other Intangible Assets.” No impairment of goodwill was indicated based on our annual analysis as of July 1, 2007. Unforeseen events and changes in circumstances and market conditions and material differences in the value of long-lived assets and intangibles due to changes in estimates of future cash flows, regulatory matters and operating costs could negatively affect the fair value of our assets and result in an impairment charge.

     Fair value is the amount at which the asset could be bought or sold in a current transaction between willing parties and may be estimated using a number of techniques, including quoted market prices or valuations by third parties, present value techniques based on estimates of cash flows, or multiples of earnings or revenue performance measures. The fair value of the asset could be different using different estimates and assumptions in these valuation techniques.

Asset Retirement Obligations

     We account for our long-lived assets under SFAS No. 143, “Accounting for Asset Retirement Obligations” (SFAS No. 143), and Financial Accounting Standards Board Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations — An Interpretation of SFAS No. 143” (FIN 47). SFAS No. 143 and FIN 47 require that an asset retirement obligation be recorded at fair value in the period in which it is incurred if a reasonable estimate of fair value can be made. In the same period, the associated asset retirement costs are capitalized as part of the carrying amount of the related long-lived asset. Rate-regulated entities may recognize regulatory assets or liabilities as a result of timing differences between the recognition of costs as recorded in accordance with SFAS No. 143 and FIN 47, and costs recovered through the ratemaking process.

     We estimate the fair value of asset retirement obligations by calculating the discounted cash flows which are dependent upon the following components:

	•		Inflation adjustment — The estimated cash flows are adjusted for inflation estimates for labor, equipment, materials, and other disposal costs;
	•		Discount rate — The estimated cash flows include contingency factors that were used as a proxy for the market risk premium; and
	•		Third-party markup adjustments — Internal labor costs included in the cash flow calculation were adjusted for costs that a third party would incur in performing the tasks necessary to retire the asset.

     Changes in these factors could materially affect the obligation recorded to reflect the ultimate cost associated with retiring the assets under SFAS No. 143 and FIN 47. For example, if the inflation adjustment increased 25 basis points, this would increase the balance for asset retirement obligations by approximately 4%. Similarly, an increase in the discount rate by 25 basis points would decrease asset retirement obligations by approximately 3%. At September 30, 2007, our estimated cost of retiring these assets was approximately $69 million.

Unbilled Revenues

     Revenues related to the sale and/or delivery of natural gas are generally recorded when natural gas is delivered to customers. However, the determination of sales to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month. At the end of each month, amounts of natural gas delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is estimated. Unbilled natural gas sales are estimated based on estimated purchased gas volumes, estimated lost and

unaccounted for gas and tariffed rates in effect. As additional information becomes available, or actual amounts are determinable, the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates.

NEW ACCOUNTING PRONOUNCEMENTS

     See Note 2 to our Interim Condensed Financial Statements 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, 2007 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 Securities and Exchange Commission’s rules and forms and such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding disclosure.

     There has been no change in our internal controls over financial reporting that occurred during the three months ended September 30, 2007 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 discussion of material legal and regulatory proceedings affecting us, please read Notes 4 and 10 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 the CERC Corp. Form 10-K.

Item 1A. Risk Factors

          Other than with respect to the risk factors set forth below, there have been no material changes from the risk factors disclosed in the CERC Corp. Form 10-K.

The states in which we provide regulated local gas distribution may, either through legislation or rules, adopt restrictions similar to those under the Public Utility Holding Company Act of 1935 Act (1935 Act) regarding organization, financing and affiliate transactions that could have significant adverse effects on our ability to operate our utility operations.

          The 1935 Act provided a comprehensive regulatory structure governing the organization, capital structure, intracompany relationships and lines of business that could be pursued by registered holding companies and their member companies. Following repeal of that Act, some states have sought to expand their own regulatory frameworks to give their regulatory authorities increased jurisdiction and scrutiny over similar aspects of the utilities that operate in their states. Some of these frameworks attempt to regulate financing activities, acquisitions and divestitures, and arrangements between the utilities and their affiliates, and to restrict the level of non-utility businesses that can be conducted within the holding company structure. Additionally they may impose record keeping, record access, employee training and reporting requirements related to affiliate transactions and reporting in the event of certain downgrading of the utility’s bond rating.

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

We and CenterPoint Energy could incur liabilities associated with businesses and assets that we have transferred to others.

          In connection with the organization and capitalization of Reliant Resources, Inc. (RRI), RRI and its subsidiaries assumed liabilities associated with various assets and businesses Reliant Energy, Incorporated (Reliant Energy) transferred to them. RRI also agreed to indemnify, and cause the applicable transferee subsidiaries to indemnify, CenterPoint Energy and its subsidiaries, including us, with respect to liabilities associated with the transferred assets and businesses. These indemnity provisions were intended to place sole financial responsibility on RRI and its subsidiaries for all liabilities associated with the current and historical businesses and operations of RRI, regardless of the time those liabilities arose. If RRI is unable to satisfy a liability that has been so assumed in circumstances in which Reliant Energy has not been released from the liability in connection with the transfer, we or CenterPoint Energy could be responsible for satisfying the liability.

          Prior to CenterPoint Energy’s distribution of its ownership in RRI to its shareholders, we had guaranteed certain contractual obligations of what became RRI’s trading subsidiary. Under the terms of the separation agreement between the companies, RRI agreed to extinguish all such guaranty obligations prior to separation, but at the time of separation in September 2002, RRI had been unable to extinguish all obligations. To secure us and CenterPoint Energy against obligations under the remaining guaranties, RRI agreed to provide cash or letters of credit for our benefit and that of CenterPoint Energy, and undertook to use commercially reasonable efforts to extinguish the remaining guaranties. We currently hold letters of credit in the amount of $29.3 million issued on behalf of RRI against guaranties that have not been released. RRI may be unable to obtain our release under some of the remaining guarantees, and one of those guarantees has been issued to support long-term transportation contracts that extend to 2018. There can be no assurance that the letters of credit we hold will be sufficient to satisfy our obligations on the remaining guaranties if RRI were to fail to perform its obligation to the counterparties, and RRI may be unable or unwilling to provide increased security from time to time to protect us if our exposures on such guarantees were to exceed the amount of the letters of credit held as security.

          RRI’s unsecured debt ratings are currently below investment grade. If RRI were unable to meet its obligations, it would need to consider, among various options, restructuring under the bankruptcy laws, in which event RRI might not honor its indemnification obligations and claims by RRI’s creditors might be made against CenterPoint Energy as its former owner.

Item 5. Other Information

Ratio of Earnings to Fixed Charges

     Our ratio of earnings to fixed charges for the nine months ended September 30, 2006 and 2007 was 2.58 and 2.87, respectively. We do not believe that the ratios for these nine-month periods are necessarily indicators of the ratios for the twelve-month periods due to the seasonal nature of our business. The ratios were calculated pursuant to applicable rules of the Securities and Exchange Commission.

Carthage to Perryville Pipeline

          In September 2007, CEGT initiated an investigation into allegations received from two former employees of the manufacturer of pipe installed in CEGT’s Carthage to Perryville pipeline segment. That pipeline segment was placed in commercial service in May 2007 after satisfactory completion of hydrostatic testing designed to ensure that the pipe and its welds would be structurally sound when placed in service and operated at design pressure. According to the complainants, records relating to radiographic inspections of certain welds made at the fabrication facility had been altered resulting in the possibility that pipe with the alleged substandard welds had been installed in the pipeline. In addition to commencing an investigation utilizing outside legal counsel and other experts, CEGT immediately informed appropriate government officials. CEGT has continued to keep those officials informed of CEGT’s activities and developments during its investigation. In conducting its investigation, among other things, CEGT has interviewed the complainants and other individuals, including CEGT and contractor personnel, and reviewed documentation related to the manufacture and construction of the pipeline, including radiographic records related to the allegedly deficient welds. CEGT has also consulted appropriate technical consultants and pre-existing regulatory guidance. Although its investigation is continuing, CEGT has found no basis, as a result of the allegations received to date, to cease or modify operations of its Carthage to Perryville line or take other significant action. CEGT further believes that, absent new findings, the Carthage to Perryville line can be operated at expected operating pressures without threat to the public health or safety.

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.

Report or

SEC File or

Exhibit

Registration

Registration

Exhibit

Number

Description

Statement

Number

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

1-13265

3(b)

December 31, 1997

4.1

–

$950,000,000 Second Amended and Restated Credit Agreement dated as of June 29, 2007, among CERC Corp., as Borrower, and the banks named therein

Form 10-Q for the quarter ended June 30, 2007

1-13265

4.1

4.2

–

Indenture, dated as of February 1, 1998, between Reliant Energy Resources Corp. and Chase Bank of Texas, National Association, as Trustee

CERC Corp.’s Form 8-K dated February 5, 1998

1-13265

4.1

4.3

–

Supplemental Indenture No. 10 to Exhibit 4.2, dated as of February 6, 2007, providing for the issuance of CERC Corp.’s 6.25% Senior Notes due 2037

CenterPoint Energy’s Form 10-K for the year ended December 31, 2006

1-31447

4(f)(11)

4.4

–

Supplemental Indenture No. 11 to Exhibit 4.2, dated as of October 23, 2007, providing for the issuance of CERC Corp.’s 6.125% Senior Notes due 2017

CenterPoint Energy’s Form 10-Q for the quarter ended September 30, 2007

1-31447

4.8

4.5

–

Supplemental Indenture No. 12 to Exhibit 4.2, dated as of October 23, 2007, providing for the issuance of CERC Corp.’s 6.625% Senior Notes due 2037

CenterPoint Energy’s Form 10-Q for the quarter ended September 30, 2007

1-31447

4.9

+12

–

Computation of Ratios of Earnings to Fixed Charges

+31.1

–

Rule 13a-14(a)/15d-14(a) Certification of David M. McClanahan

+31.2

–

Rule 13a-14(a)/15d-14(a) Certification of Gary L. Whitlock

+32.1

–

Section 1350 Certification of David M. McClanahan

+32.2

–

Section 1350 Certification of Gary L. Whitlock

+99.1

–

Items incorporated by reference from the CERC Corp. Form 10-K. Item 1A “—Risk Factors.”

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.

Date: November 7, 2007

EXHIBIT INDEX

     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.

Report or

SEC File or

Exhibit

Registration

Registration

Exhibit

Number

Description

Statement

Number

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

1-13265

3(b)

December 31, 1997

4.1

–

$950,000,000 Second Amended and Restated Credit Agreement dated as of June 29, 2007, among CERC Corp., as Borrower, and the banks named therein

Form 10-Q for the quarter ended June 30, 2007

1-13265

4.1

4.2

–

Indenture, dated as of February 1, 1998, between Reliant Energy Resources Corp. and Chase Bank of Texas, National Association, as Trustee

CERC Corp.’s Form 8-K dated February 5, 1998

1-13265

4.1

4.3

–

Supplemental Indenture No. 10 to Exhibit 4.2, dated as of February 6, 2007, providing for the issuance of CERC Corp.’s 6.25% Senior Notes due 2037

CenterPoint Energy’s Form 10-K for the year ended December 31, 2006

1-31447

4(f)(11)

4.4

–

Supplemental Indenture No. 11 to Exhibit 4.2, dated as of October 23, 2007, providing for the issuance of CERC Corp.’s 6.125% Senior Notes due 2017

CenterPoint Energy’s Form 10-Q for the quarter ended September 30, 2007

1-31447

4.8

4.5

–

Supplemental Indenture No. 12 to Exhibit 4.2, dated as of October 23, 2007, providing for the issuance of CERC Corp.’s 6.625% Senior Notes due 2037

CenterPoint Energy’s Form 10-Q for the quarter ended September 30, 2007

1-31447

4.9

+12

–

Computation of Ratios of Earnings to Fixed Charges

+31.1

–

Rule 13a-14(a)/15d-14(a) Certification of David M. McClanahan

+31.2

–

Rule 13a-14(a)/15d-14(a) Certification of Gary L. Whitlock

+32.1

–

Section 1350 Certification of David M. McClanahan

+32.2

–

Section 1350 Certification of Gary L. Whitlock

+99.1

–

Items incorporated by reference from the CERC Corp. Form 10-K. Item 1A “—Risk Factors.”