Centerpoint Energy Resources 10-Q 2008 Q3 Quarterly report

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, 2008

OR

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

FOR THE TRANSITION PERIOD FROM _________ TO _____________.

______________________________

Commission file number 1-13265

CENTERPOINT ENERGY RESOURCES CORP.

(Exact name of registrant as specified in its charter)

Delaware	76-0511406
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
1111 Louisiana
Houston, Texas 77002	(713) 207-1111
(Address and zip code of principal executive offices)	(Registrant’s telephone number, including area code)

____________________________

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

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

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

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

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

As of October 31, 2008, 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, 2008

TABLE OF CONTENTS

PART I.	FINANCIAL INFORMATION
Item 1.	Financial Statements	1
	Condensed Statements of Consolidated Income
	Three and Nine Months Ended September 30, 2007 and 2008 (unaudited)	1
	Condensed Consolidated Balance Sheets
	December 31, 2007 and September 30, 2008 (unaudited)	2
	Condensed Statements of Consolidated Cash Flows
	Nine Months Ended September 30, 2007 and 2008 (unaudited)	4
	Notes to Unaudited Condensed Consolidated Financial Statements	5
Item 2.	Management’s Narrative Analysis of the Results of Operations	19
Item 4T.	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	29

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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, environmental regulations, including regulations related to global climate change, and 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, including those associated with Hurricane Ike, and a reasonable return on investment;

· cost overruns on major capital projects that cannot be recouped in prices;

· 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;

· weather variations and other natural phenomena;

· changes in interest rates or rates of inflation;

· 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;

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

· the ability of Reliant Energy, Inc. and its subsidiaries to satisfy their obligations to us, including indemnity obligations, or 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’s employee benefit plans;

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· 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;

· acquisition and merger activities involving our parent or our competitors; 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, 2007, which is incorporated herein by reference, “Risk Factors” in Item 1A of Part II of this Quarterly Report on Form 10-Q and other reports we file from time to time with the Securities and Exchange Commission.

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

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PART I.  FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

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

CONDENSED STATEMENTS OF CONSOLIDATED INCOME

(Millions of Dollars)

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2008			2007			2008
Revenues	$	1,351		$	1,960		$	5,614		$	7,069
Expenses:
Natural gas		990			1,532			4,348			5,675
Operation and maintenance		191			212			577			601
Depreciation and amortization		56			54			159			163
Taxes other than income taxes		23			33			106			129
Total		1,260			1,831			5,190			6,568
Operating Income		91			129			424			501
Other Income (Expense): Interest and other finance charges		(51	)		(51	)		(135	)		(148	)
Other, net		7			26			14			53
Total		(44	)		(25	)		(121	)		(95	)
Income Before Income Taxes		47			104			303			406
Income tax expense		(19	)		(37	)		(114	)		(153	)
Net Income	$	28		$	67		$	189		$	253

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

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CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

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

CONDENSED CONSOLIDATED BALANCE SHEETS

(Millions of Dollars)

(Unaudited)

ASSETS

	December 31, 2007		September 30, 2008
Current Assets:
Cash and cash equivalents	$	1	$	1
Accounts and notes receivable, net		732		587
Accrued unbilled revenue		456		132
Accounts and notes receivable – affiliated companies		82		19
Materials and supplies		35		49
Natural gas inventory		395		598
Non-trading derivative assets		38		75
Taxes receivable		—		26
Deferred tax asset		40		10
Prepaid expenses and other current assets		235		289
Total current assets		2,014		1,786
Property, Plant and Equipment:
Property, plant and equipment		5,837		6,166
Less accumulated depreciation and amortization		806		917
Property, plant and equipment, net		5,031		5,249
Other Assets:
Goodwill		1,696		1,696
Non-trading derivative assets		11		9
Notes receivable from unconsolidated affiliates		148		323
Other		234		508
Total other assets		2,089		2,536
Total Assets	$	9,134	$	9,571

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

2

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, 2007		September 30, 2008
Current Liabilities:
Short-term borrowings	$	232	$	150
Current portion of long-term debt		307		6
Accounts payable		661		546
Accounts and notes payable — affiliated companies		144		54
Taxes accrued		118		84
Interest accrued		59		70
Customer deposits		59		57
Non-trading derivative liabilities		60		49
Other		186		192
Total current liabilities		1,826		1,208
Other Liabilities:
Accumulated deferred income taxes, net		778		817
Non-trading derivative liabilities		14		20
Benefit obligations		116		113
Regulatory liabilities		474		498
Other		167		122
Total other liabilities		1,549		1,570
Long-term Debt		2,645		3,532
Commitments and Contingencies (Note 10)
Stockholder’s Equity:
Common stock		—		—
Paid-in capital		2,406		2,406
Retained earnings		692		845
Accumulated other comprehensive income		16		10
Total stockholder’s equity		3,114		3,261
Total Liabilities and Stockholder’s Equity	$	9,134	$	9,571

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

3

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

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

CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

(Millions of Dollars)

(Unaudited)

	Nine Months Ended September 30,
	2007			2008
Cash Flows from Operating Activities:
Net income	$	189		$	253
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		159			163
Amortization of deferred financing costs		6			7
Deferred income taxes		60			62
Write-down of natural gas inventory		11			24
Changes in other assets and liabilities:
Accounts receivable and unbilled revenues, net		609			469
Accounts receivable/payable, affiliates		16			40
Inventory		(159	)		(241	)
Taxes receivable		(47	)		(26	)
Accounts payable		(446	)		(118	)
Fuel cost recovery		(90	)		(11	)
Interest and taxes accrued		(28	)		(23	)
Non-trading derivatives, net		14			(22	)
Margin deposits, net		49			(96	)
Other current assets		(31	)		20
Other current liabilities		(30	)		(16	)
Other assets		(27	)		(46	)
Other liabilities		(56	)		(37	)
Other, net		—			(33	)
Net cash provided by operating activities		199			369
Cash Flows from Investing Activities:
Capital expenditures		(519	)		(358	)
Increase in notes receivable from affiliates, net		(51	)		(175	)
Investment in unconsolidated affiliates		(40	)		(207	)
Other, net		(10	)		34
Net cash used in investing activities		(620	)		(706	)
Cash Flows from Financing Activities:
Decrease in short-term borrowings, net		(37	)		(82	)
Long-term revolving credit facility, net		360			595
Proceeds from long-term debt		150			300
Payments of long-term debt		(7	)		(307	)
Decrease in notes payable to affiliates		(47	)		(67	)
Debt issuance costs		(2	)		(2	)
Dividend to parent		—			(100	)
Other, net		2			—
Net cash provided by financing activities		419			337
Net Decrease in Cash and Cash Equivalents		(2	)		—
Cash and Cash Equivalents at Beginning of Period		5			1
Cash and Cash Equivalents at End of Period	$	3		$	1
Supplemental Disclosure of Cash Flow Information:
Cash Payments:
Interest, net of capitalized interest	$	123		$	137
Income taxes		129			148
Non-cash transactions:
Accounts payable related to capital expenditures		53			54

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

4

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. (CERC Corp.) are the condensed consolidated interim financial statements and notes (Interim Condensed Financial Statements) of CenterPoint Energy Resources Corp. and its subsidiaries (collectively, CERC 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, 2007 (CERC Corp. Form 10-K).

Background.  The Company owns and operates natural gas distribution systems in six states. Subsidiaries of the Company own interstate natural gas pipelines and gas gathering systems and provide various ancillary services. A 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 generally accepted accounting principles (GAAP) 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.

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

(2) New Accounting Pronouncements

In April 2007, the Financial Accounting Standards Board (FASB) issued Staff Position No. FIN 39-1, “Amendment of FASB Interpretation No. 39” (FIN 39-1), which permits companies that enter into master netting arrangements to offset cash collateral receivables or payables with net derivative positions under certain circumstances. The Company adopted FIN 39-1 effective January 1, 2008 and began netting the cash collateral receivables and payables and also its derivative assets and liabilities with the same counterparty subject to master netting agreements.

In February 2007, the FASB issued Statement of Financial Accounting Standards (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 but is not required to be applied. The Company currently has no plans to apply SFAS No. 159.

In December 2007, the FASB issued SFAS No. 141 (Revised 2007), “Business Combinations” (SFAS No. 141R). SFAS No. 141R will significantly change the accounting for business combinations. Under SFAS No. 141R, an acquiring entity will be required to recognize all the assets acquired and liabilities assumed in a transaction at the acquisition date fair value with limited exceptions. SFAS No. 141R also includes a substantial number of new

5

disclosure requirements and applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. As the provisions of SFAS No. 141R are applied prospectively, the impact to the Company cannot be determined until applicable transactions occur.

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements - An Amendment of ARB No. 51” (SFAS No. 160). SFAS No. 160 establishes new accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. This accounting standard is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. The Company will adopt SFAS No. 160 as of January 1, 2009. The Company expects that the adoption of SFAS No. 160 will not have a material impact on its financial position, results of operations or cash flows.

Effective January 1, 2008, the Company adopted SFAS No. 157, “Fair Value Measurements” (SFAS No. 157), which requires additional disclosures about the Company’s financial assets and liabilities that are measured at fair value. FASB Staff Position No. FAS 157-2 delays the effective date for SFAS No. 157 for nonfinancial assets and liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis, to fiscal years, and interim periods within those fiscal years, beginning after November 15, 2008. The Company has elected to defer the adoption of SFAS No. 157 for its goodwill impairment test and the measurement of asset retirement obligations until January 1, 2009, as permitted.  Beginning in January 2008, assets and liabilities recorded at fair value in the Condensed Consolidated Balance Sheet are categorized based upon the level of judgment associated with the inputs used to measure their value. Hierarchical levels, as defined in SFAS No. 157 and directly related to the amount of subjectivity associated with the inputs to fair valuations of these assets and liabilities, are as follows:

Level 1: Inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date. The types of assets carried at Level 1 fair value generally are financial derivatives, investments and equity securities listed in active markets.

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

Level 3: Inputs are unobservable for the asset or liability, and include situations where there is little, if any, market activity for the asset or liability. In certain cases, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. In such cases, the level in the fair value hierarchy within which the fair value measurement in its entirety falls has been determined based on the lowest level input that is significant to the fair value measurement in its entirety. The Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment, and considers factors specific to the asset. Generally, assets and liabilities carried at fair value and included in this category are financial derivatives.

The following table presents information about the Company’s assets and liabilities (including derivatives that are presented net) measured at fair value on a recurring basis as of September 30, 2008, and indicates the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair value.

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	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Netting Adjustments (1)			Balance as of September 30, 2008
	(in millions)
Assets
Corporate equities	$	2	$	—	$	—	$	—		$	2
Investments		11		—		—		—			11
Derivative assets		24		111		38		(89	)		84
Total assets	$	37	$	111	$	38	$	(89	)	$	97
Liabilities
Derivative liabilities	$	31	$	124	$	97	$	(183	)	$	69
Total liabilities	$	31	$	124	$	97	$	(183	)	$	69

(1) Amounts represent the impact of legally enforceable master netting agreements that allow the Company to settle positive and negative positions and also cash collateral held or placed with the same counterparties.

The following table presents additional information about assets or liabilities, including derivatives that are measured at fair value on a recurring basis for which the Company has utilized Level 3 inputs to determine fair value, for the three months ended September 30, 2008:

	Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Derivative assets and liabilities, net
	(in millions)
Beginning asset (liability) balance as of July 1, 2008	$	6
Total gains or (losses) (realized and unrealized):
Included in deferred fuel cost recovery		(59	)
Included in earnings		(2	)
Purchases, sales, other settlements, net		(4	)
Ending asset (liability) balance as of September 30, 2008	$	(59	)
The amount of total gains or (losses) for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the reporting date	$	4

The following table presents additional information about assets or liabilities, including derivatives that are measured at fair value on a recurring basis for which the Company has utilized Level 3 inputs to determine fair value, for the nine months ended September 30, 2008:

	Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Derivative assets and liabilities, net
	(in millions)
Beginning asset (liability) balance as of July 1, 2008	$	(3	)
Total gains or (losses) (realized and unrealized):
Included in deferred fuel cost recovery		(59	)
Included in earnings		7
Purchases, sales, other settlements, net		(4	)
Ending asset (liability) balance as of September 30, 2008	$	(59	)
The amount of total gains or (losses) for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the reporting date	$	9

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In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities - an amendment of FASB Statement No. 133” (SFAS No. 161). SFAS No. 161 amends SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS No. 133) and requires enhanced disclosures of derivative instruments and hedging activities, such as the fair value of derivative instruments and presentation of their gains or losses in tabular format, as well as disclosures regarding credit risks and strategies and objectives for using derivative instruments. SFAS No. 161 is effective for fiscal years and interim periods beginning after November 15, 2008. The Company is currently evaluating the potential impact the adoption of SFAS No. 161 will have on its consolidated financial statements.

(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 September 30,						Nine Months Ended September 30,
	2007			2008			2007			2008
	(in millions)
Service cost	$	1		$	—		$	1		$	—
Interest cost		1			2			5			6
Expected return on plan assets		(1	)		(1	)		(1	)		(1	)
Amortization of prior service cost		1			1			2			2
Net periodic cost	$	2		$	2		$	7		$	7

The Company expects to contribute approximately $14 million to CenterPoint Energy’s postretirement benefits plan in 2008, of which $4 million and $11 million, respectively, was contributed during the three and nine months ended September 30, 2008.

(4) Regulatory Matters

(a) Hurricane Ike

The Company’s natural gas distribution business (Gas Operations) suffered some damage to its system in Houston, Texas and in other portions of its service territory across Texas and Louisiana as a result of Hurricane Ike, which struck the upper Texas coast in September 2008. As of September 30, 2008, Gas Operations has deferred approximately $3 million of costs related to Hurricane Ike for recovery as part of future natural gas distribution rate proceedings.

(b) Rate Proceedings

Texas. In March 2008, Gas Operations filed a request to change its rates with the Railroad Commission of Texas (Railroad Commission) and the 47 cities in its Texas Coast service territory, an area consisting of approximately 230,000 customers in cities and communities on the outskirts of Houston. The request sought to establish uniform rates, charges and terms and conditions of service for the cities and environs of the Texas Coast service territory. Of the 47 cities, 23 either affirmatively approved or allowed the filed rates to go into effect by operation of law.  Nine other cities are represented by the Texas Coast Utilities Coalition (TCUC) and 15 cities are represented by the Gulf Coast Coalition of Cities (GCCC). The TCUC cities denied the rate change request and Gas Operations appealed the denial of rates to the Railroad Commission. The Railroad Commission issued an order in October 2008, which, if implemented across the entire Texas Coast service territory, would result in an annual revenue increase of $3.7 million.  In July 2008, Gas Operations reached a settlement agreement with the GCCC. That settlement agreement, if implemented across the entire Texas Coast service territory, would allow Gas Operations a $3.4 million annual increase in revenues.  Both the Railroad Commission order and the settlement provide for an annual rate adjustment mechanism to reflect changes in operating expenses and revenues as well as changes in capital investment and associated changes in revenue-related taxes. The impact of the Railroad Commission’s order on the settled rates is still under review and how rates will be conformed among all cities in the Texas Coast service territory is unknown at this time.

8

Minnesota. In November 2006, the Minnesota Public Utilities Commission (MPUC) denied a request filed by Gas Operations for a waiver of MPUC rules in order to allow Gas Operations to recover approximately $21 million in unrecovered purchased gas costs related to periods prior to July 1, 2004. Those unrecovered gas costs were identified as a result of revisions to previously approved calculations of unrecovered purchased gas costs. Following that denial, Gas Operations recorded a $21 million adjustment to reduce pre-tax earnings in the fourth quarter of 2006 and reduced the regulatory asset related to these costs by an equal amount. In March 2007, following the MPUC’s denial of reconsideration of its ruling, Gas Operations petitioned the Minnesota Court of Appeals for review of the MPUC’s decision, and in May 2008 that court ruled that the MPUC had been arbitrary and capricious in denying Gas Operations a waiver. The court ordered the case remanded to the MPUC for reconsideration under the same principles the MPUC had applied in previously granted waiver requests. The MPUC sought further review of the court of appeals decision from the Minnesota Supreme Court, and in July 2008, the Minnesota Supreme Court agreed to review the decision.  However, a decision from the court is not expected until the first half of 2009.  No prediction can be made as to the ultimate outcome of this matter.

In November 2008, Gas Operations filed a request with the MPUC to increase its rates for utility distribution service.  If approved by the MPUC, the proposed new rates would result in an overall increase in annual revenue of $59.8 million.  The proposed increase would allow Gas Operations to recover increased operating costs, including higher bad debt and collection expenses, the cost of improved customer service and inflationary increases in other expenses.  It also would allow recovery of increased costs related to conservation improvement programs, adjust rates to reflect the impact of decreased use per customer and provide a return for the additional capital invested to serve its customers.  In addition, Gas Operations is seeking an adjustment mechanism that would annually adjust rates to reflect changes in use per customer.  Interim rates are expected to be effective January 2009 but will be subject to refund.  The MPUC is allowed ten months to issue a final decision; however, an extension of time can occur in certain circumstances.

(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 to mitigate the impact of changes in commodity prices and weather on its operating results and cash flows.

(a) Non-Trading Activities

Cash Flow Hedges. The Company has entered into certain derivative instruments that qualify as cash flow hedges under 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 each of the three and nine months ended September 30, 2007 and 2008, hedge ineffectiveness was less than $1 million 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 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 Statements of Consolidated Cash Flows in the same category as the item being hedged. As of September 30, 2008, the Company expects less than $1 million 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 derivative instruments that have been designated and have qualified as cash flow hedging instruments is less than one year. 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, 2007, the Company decreased natural gas expense from unrealized net gains of $2 million. During the nine months

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ended September 30, 2007, the Company increased natural gas expense from unrealized net losses of $12 million. During the three months ended September 30, 2008, the Company increased revenues from unrealized net gains of $80 million and increased natural gas expense from unrealized net losses of $34 million, a net unrealized gain of $46 million. During the nine months ended September 30, 2008, the Company increased revenues from unrealized net gains of $51 million and increased natural gas expense from unrealized net losses of $37 million, a net unrealized gain of $14 million.

Weather Derivatives. The Company has weather normalization or other rate mechanisms that mitigate the impact of weather in Arkansas, Louisiana, Oklahoma and a portion of Texas. The remaining Gas Operations jurisdictions, Minnesota, Mississippi and most of Texas, do not have such mechanisms. As a result, fluctuations from normal weather may have a significant positive or negative effect on the results of these operations.

In 2007, the Company entered into heating-degree day swaps to mitigate the effect of fluctuations from normal weather on its financial position and cash flows for the 2007/2008 winter heating season. The swaps were based on ten-year normal weather and provided for a maximum payment by either party of $18 million. During the three and nine months ended September 30, 2008, the Company recognized losses of $-0- and $13 million, respectively, related to these swaps. The loss for the nine months ended September 30, 2008 was offset in part by increased revenues due to colder than normal weather. These weather derivative losses are included in revenues in the Condensed Statements of Consolidated Income.

In July 2008, the Company entered into heating-degree day swaps to mitigate the effect of fluctuations from normal weather on its financial position and cash flows for the 2008/2009 winter heating season. The swaps are based on ten-year normal weather and provide for a maximum payment by either party of $11 million.

(6) Goodwill

Goodwill by reportable business segment as of both December 31, 2007 and September 30, 2008 is as follows (in millions):

Natural Gas Distribution	$	746
Interstate Pipelines		579
Competitive Natural Gas Sales and Services		335
Field Services		25
Other Operations		11
Total	$	1,696

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, 2008, the Company’s annual impairment testing date, and determined that no impairment charge for goodwill was required.

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(7) Comprehensive Income

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

	For the Three Months Ended September 30,					For the Nine Months Ended September 30,
	2007		2008			2007			2008
	(in millions)
Net income	$	28	$	67		$	189		$	253
Other comprehensive income (loss):
SFAS No. 158 adjustment (net of tax of $-0-, $1,  $-0- and $1)		—		(1	)		1			(1	)
Net deferred gain from cash flow hedges (net of tax  of $3, $-0-, $6 and $-0-)		6		—			11			—
Reclassification of deferred gain from cash flow  hedges realized in net income (net of tax of $-0-,  $-0-,$17 and $2)		—		(1	)		(27	)		(5	)
Other comprehensive income (loss)		6		(2	)		(15	)		(6	)
Comprehensive income	$	34	$	65		$	174		$	247

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

	December 31, 2007		September 30, 2008
	(in millions)
SFAS No. 158 adjustment	$	11	$	10
Net deferred gain from cash flow hedges		5		—
Total accumulated other comprehensive income	$	16	$	10

(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 by CenterPoint Energy under its revolving credit facility or the sale by CenterPoint Energy of its commercial paper. As of December 31, 2007 and September 30, 2008, the Company had borrowings from the money pool of $67 million and $-0-, respectively.

For each of the three-month periods ended September 30, 2007 and 2008, the Company had net interest expense related to affiliate borrowings of less than $1 million. For each of the nine-month periods ended September 30, 2007 and 2008, the Company had net interest expense related to affiliate borrowings of approximately $1 million.

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 $34 million and $35 million for the three months ended September 30, 2007 and 2008, respectively, and $99 million and $105 million for the nine months ended September 30, 2007 and 2008, respectively, and are included primarily in operation and maintenance expenses.

The Company paid a dividend of $100 million to its parent during the three months ended September 30, 2008.

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

(a) Short-term Borrowings

The Company’s receivables facility terminated on October 28, 2008. The facility size ranged from $150 million to $375 million during the period from September 30, 2007 to the October 28, 2008 termination date. The variable

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size of the facility tracked the seasonal pattern of receivables in the Company’s natural gas businesses. At September 30, 2008, the facility size was $150 million. As of December 31, 2007 and September 30, 2008, $232 million and $150 million, respectively, was advanced for the purchase of receivables under this receivables facility.  Advances under the receivables facility of $150 million were repaid upon termination of the facility.  The Company is currently negotiating a new receivables facility to replace the expired facility, but there can be no assurance that a new facility with acceptable terms can be obtained.

(b) Long-term Debt

In May 2008, the Company issued $300 million aggregate principal amount of senior notes due in May 2018 with an interest rate of 6.00%. The proceeds from the sale of the senior notes were used for general corporate purposes, including capital expenditures, working capital and loans to or investments in affiliates. Pending application of the net proceeds from this offering for these purposes, the Company repaid borrowings under its senior unsecured revolving credit facility and borrowings from its affiliates.

Revolving Credit Facility.  As of December 31, 2007 and September 30, 2008, the Company had borrowings of $150 million and $745 million, respectively, under its $950 million credit facility. There was no commercial paper outstanding that would have been backstopped by the Company’s credit facility at December 31, 2007 and September 30, 2008. The Company was in compliance with all debt covenants as of September 30, 2008.

(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, 2007 and September 30, 2008 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, 2008, minimum payment obligations for natural gas supply commitments are approximately $301 million for the remaining three months in 2008, $631 million in 2009, $302 million in 2010, $293 million in 2011, $283 million in 2012 and $1.1 billion after 2012.

(b) Legal, Environmental and Other Regulatory Matters

Legal Matters

RRI Indemnified Litigation

CenterPoint Energy or its predecessor, Reliant Energy, Incorporated (Reliant Energy), and certain of their present or former subsidiaries are named as defendants in several lawsuits described below. Under a master separation agreement between CenterPoint Energy and Reliant Energy, Inc. (formerly Reliant Resources, Inc.) (RRI), CenterPoint Energy and its subsidiaries, including the Company,  are entitled to be indemnified by RRI for any losses, including attorneys’ fees and other costs, arising out of the lawsuits described below under “Gas Market Manipulation Cases.” Pursuant to the indemnification obligation, RRI is defending CenterPoint Energy and its subsidiaries to the extent named in these lawsuits. Although the ultimate outcome of these matters cannot be predicted at this time, CenterPoint Energy has not considered it necessary to establish reserves related to this litigation.

Gas Market Manipulation Cases. A large number of lawsuits were filed against numerous gas market participants in a number of federal and western state courts in connection with the operation of the natural gas markets in 2000-2001. CenterPoint Energy’s former affiliate, RRI, was a participant in gas trading in the California and Western markets. These lawsuits, many of which have been filed as class actions, allege violations of state and federal antitrust laws. Plaintiffs in these lawsuits are seeking a variety of forms of relief, including recovery of compensatory damages (in some cases in excess of $1 billion), a trebling of compensatory damages, full consideration damages and attorneys’ fees.  CenterPoint Energy and/or Reliant Energy were named in approximately 30 of these lawsuits, which were instituted between 2003 and 2007. In October 2006, RRI reached a

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settlement of 11 class action natural gas cases pending in state court in California. The court approved this settlement in June 2007. In the other gas cases consolidated in state court in California, the Court of Appeals found that CenterPoint Energy was not a successor to the liabilities of a subsidiary of RRI, and CenterPoint Energy was dismissed from these suits in April 2008. In the Nevada federal litigation, three of the complaints were dismissed based on defendants’ filed rate doctrine defense, but the Ninth Circuit Court of Appeals reversed those dismissals and remanded the cases back to the district court for further proceedings.  In July 2008, the plaintiffs in four of the federal court cases agreed to dismiss CenterPoint Energy from those cases. In August 2008, the plaintiffs in five additional cases also agreed to dismiss CenterPoint Energy from those cases, but one of these plaintiffs has moved to amend its complaint to add CenterPoint Energy Services, Inc., a subsidiary of the Company, as a defendant in that case.  As a result, CenterPoint Energy remains a party in only two remaining gas market manipulation cases, one pending in Nevada state court in Clark County and one in federal district court in Nevada.  CenterPoint Energy believes it is not a proper defendant in the remaining cases and will continue to pursue dismissal from those cases.

Other 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. In October 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, a lawsuit was filed on behalf of certain ratepayers of the Company in state district court in Wharton County, Texas against CERC Corp., 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 Pipeline Services, Inc. (CEPS), and certain other subsidiaries of CERC Corp., 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, a lawsuit was filed by certain ratepayers of the Company in Texas and Arkansas in circuit court in Miller County, Arkansas against CERC Corp., CenterPoint Energy, EGMC, CenterPoint Energy Gas Transmission Company (CEGT), CenterPoint Energy Field Services (CEFS), CEPS, Mississippi River Transmission

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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 CEGT and MRT as defendants. Although the plaintiffs in the Miller County case sought class certification, no class was certified. In June 2007, the Arkansas Supreme Court determined that the Arkansas claims were within the sole and exclusive jurisdiction of the Arkansas Public Service Commission (APSC). In response to that ruling, in August 2007 the Miller County court stayed but refused to dismiss the Arkansas claims. In February 2008, the Arkansas Supreme Court directed the Miller County court to dismiss the entire case for lack of jurisdiction. The Miller County court subsequently dismissed the case in accordance with the Arkansas Supreme Court’s mandate and all appellate deadlines have expired.

In June 2007, CERC Corp., 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 exclusive original jurisdiction over the Texas claims asserted in the Miller County case. In October 2007, CEFS and CEPS joined the petition in the Travis County case.  In October 2008, the district court ruled that the Railroad Commission had exclusive original jurisdiction over the Texas claims asserted against CERC Corp., CenterPoint Energy, EGMC and the other defendants in the Miller County case.  The time has not yet run for an appeal of this ruling.

In August 2007, the Arkansas plaintiff in the Miller County litigation 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. That complaint remains pending at the APSC.

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 lawsuits were stayed pending the resolution of the petitions filed with 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 the LPSC 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, including interest, related to certain off-system sales. The refund will be completed in the fourth quarter of 2008. A similar review by the LPSC related to the Caddo Parish litigation was resolved without additional payment by the Company. In October 2008, the courts considering the Caddo and Calcasieu Parish cases dismissed these cases pursuant to motions to dismiss.   Although the time for appeal of that dismissal has not run, the Company believes these proceedings have been substantially concluded.

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 an entity of the Company 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 the 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 Federal Energy Regulatory Commission 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 that 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.

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Environmental Matters

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, 2008, 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, 2008, 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 the suit 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.

Groundwater Contamination Litigation. Predecessor entities of the Company, along with several other entities, are defendants in litigation, St. Michel Plantation, LLC, et al, v. White, et al., pending in civil district court in Orleans Parish, Louisiana.  In the lawsuit, the plaintiffs allege that their property in Terrebonne Parish, Louisiana suffered salt water contamination as a result of oil and gas drilling activities conducted by the defendants.  Although a predecessor of the Company held an interest in two oil and gas leases on a portion of the property at issue, neither it nor any other Company entities drilled or conducted other oil and gas operations on those leases.  In July 2008, experts for the plaintiffs filed a report in this litigation in which they claimed that it would cost approximately $105

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million to remediate the alleged contamination on property covered by the leases in which the defendants, including the Company’s predecessor company, held interests.  The Company’s experts, however, believe that the claims of plaintiffs’ experts are greatly exaggerated and that actual costs for remediation would be materially less than the amounts asserted in the report of the plaintiffs’ experts.  The Company is disputing responsibility for remediation of this property and does not expect the outcome of this litigation to have a material adverse impact on the financial condition, results of operations or cash flows of the Company.

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 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 against obligations under the remaining guaranties, RRI agreed to provide cash or letters of credit for the Company’s benefit, and undertook to use commercially reasonable efforts to extinguish the remaining guaranties. In December 2007, the Company, CenterPoint Energy and RRI amended that agreement and the Company released the letters of credit it held as security. Under the revised agreement RRI agreed to provide cash or new letters of credit to secure the Company against exposure under the remaining guaranties as calculated under the new agreement if and to the extent changes in market conditions exposed the Company to a risk of loss on those guaranties.

The Company’s potential exposure under the guaranties relates to payment of demand charges related to transportation contracts. RRI continues to meet its obligations under the contracts, and, on the basis of current market conditions, the Company and CenterPoint Energy believe that additional security is not needed at this time. However, if RRI should fail to perform its obligations under the contracts or if RRI should fail to provide adequate security in the event market conditions change adversely, the Company would retain exposure to the counterparty under the guaranty.

(11) Income Taxes

During the three months and nine months ended September 30, 2007, the effective tax rate was 41% and 38%, respectively. During the three months and nine months ended September 30, 2008, the effective tax rate was 36% and 38%, respectively.

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The following table summarizes the Company’s uncertain tax positions in accordance with FASB Interpretation No. (FIN) 48, “Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109,” at December 31, 2007 and September 30, 2008 (in millions):

	December 31, 2007			September 30, 2008
Receivable for uncertain tax positions	$	(11	)	$	(12	)
Portion of receivable for uncertain tax positions that, if recognized, would reduce the effective income tax rate		1			1
Interest accrued on uncertain tax positions		(3	)		(4	)

(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. The Interstate Pipelines business segment includes the interstate natural gas pipeline operations. The Field Services business segment includes the natural gas gathering operations. Our Other Operations business segment includes unallocated corporate costs and inter-segment eliminations.

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

	For the Three Months Ended September 30, 2007
	Revenues from External Customers		Net Intersegment Revenues			Operating 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 Three Months Ended September 30, 2008
	Revenues from External Customers		Net Intersegment Revenues			Operating Income (Loss)
Natural Gas Distribution	$	548	$	2		$	(6	)
Competitive Natural Gas Sales and Services		1,256		13			35
Interstate Pipelines		96		47			55	(1)
Field Services		60		11			44
Other Operations		—		—			1
Eliminations		—		(73	)		—
Consolidated	$	1,960	$	—		$	129

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	For the Nine Months Ended September 30, 2007
	Revenues from External Customers		Net Intersegment Revenues			Operating Income (Loss)			Total Assets as of December 31, 2007
Natural Gas Distribution	$	2,594	$	7		$	129		$	4,332
Competitive Natural Gas Sales and Services		2,679		36			56			1,221
Interstate Pipelines		247		101			166			3,007
Field Services		94		31			75			669
Other Operations		—		—			(2	)		670
Eliminations		—		(175	)		—			(765	)
Consolidated	$	5,614	$	—		$	424		$	9,134

	For the Nine Months Ended September 30, 2008
	Revenues from External Customers		Net Intersegment Revenues			Operating Income (Loss)			Total Assets as of September 30, 2008
Natural Gas Distribution	$	2,969	$	7		$	119		$	4,354
Competitive Natural Gas Sales and Services		3,599		33			36			1,193
Interstate Pipelines		337		131			227	(1)		3,539
Field Services		164		27			121	(2)		792
Other Operations		—		—			(2	)		484
Eliminations		—		(198	)		—			(791	)
Consolidated	$	7,069	$	—		$	501		$	9,571

 

(1) Included in operating income of Interstate Pipelines for the three and nine months ended September 30, 2008 is a $7 million loss on pipeline assets removed from service and included in operating income of Interstate Pipelines for the nine months ended September 30, 2008 is an $18 million gain on the sale of two storage development projects.

(2) Included in operating income of Field Services for the nine months ended September 30, 2008 is an $11 million gain related to a settlement and contract buyout of one of its customers and a $6 million gain on the sale of assets.

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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 and our Annual Report on Form 10-K for the year ended December 31, 2007 (2007 Form 10-K).

We meet the conditions specified in General Instruction H(1)(a) and (b) to Form 10-Q and are therefore permitted to use the reduced disclosure format for wholly owned subsidiaries of reporting companies. Accordingly, we have omitted from this report the information called for by Item 2 (Management’s Discussion and Analysis of Financial Condition and Results of Operations) and Item 3 (Quantitative and Qualitative Disclosures About Market Risk) of Part I and the following Part II items of Form 10-Q: Item 2 (Unregistered Sales of Equity Securities and Use of Proceeds), Item 3 (Defaults Upon Senior Securities) and Item 4 (Submission of Matters to a Vote of Security Holders). The following discussion explains material changes in our revenue and expense items between the three and nine months ended September 30, 2007 and the three and nine months ended September 30, 2008. Reference is made to “Management’s Narrative Analysis of the Results of Operations” in Item 7 of our 2007 Form 10-K.

EXECUTIVE SUMMARY

Recent Events

Hurricane Ike

Our natural gas distribution business (Gas Operations) suffered some damage to its system in Houston, Texas and in other portions of its service territory across Texas and Louisiana as a result of Hurricane Ike, which struck the upper Texas coast early Saturday, September 13, 2008. As of September 30, 2008, Gas Operations has deferred approximately $3 million of costs related to Hurricane Ike for recovery as part of future natural gas distribution rate proceedings.

Receivables Facility

Our receivables facility terminated on October 28, 2008. Advances under the receivables facility of $150 million were repaid upon termination of the facility.  We are currently negotiating a new receivables facility to replace the expired facility, but there can be no assurance that a new facility with acceptable terms can be obtained.

Interstate Pipeline Expansion

Southeast Supply Header.  The Southeast Supply Header (SESH) pipeline project, a joint venture between CenterPoint Energy Gas Transmission, our wholly owned subsidiary, and Spectra Energy Corp., received Federal Energy Regulatory Commission (FERC) approval to begin operation with limited exclusions in August 2008.  The pipeline was placed into commercial service on September 6, 2008.   This new 270-mile pipeline, which extends from the Perryville Hub, near Perryville, Louisiana, to an interconnection with the Gulf Stream Natural Gas System near Mobile, Alabama, has a maximum design capacity of approximately 1 billion cubic feet per day.  The pipeline represents a new source of natural gas supply for the Southeast United States and offers greater supply diversity to this region. We now expect our share of SESH’s net costs to be approximately $620 million.

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 our 2007 Form 10-K and “Risk Factors” in Item 1A of Part II of this Quarterly Report on Form 10-Q.

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The following table sets forth our consolidated results of operations for the three and nine months ended September 30, 2007 and 2008, 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,
	2007			2008			2007			2008
	(in millions)
Revenues	$	1,351		$	1,960		$	5,614		$	7,069
Expenses:
Natural gas		990			1,532			4,348			5,675
Operation and maintenance		191			212			577			601
Depreciation and amortization		56			54			159			163
Taxes other than income taxes		23			33			106			129
Total Expenses		1,260			1,831			5,190			6,568
Operating Income		91			129			424			501
Interest and Other Finance Charges		(51	)		(51	)		(135	)		(148	)
Other Income, net		7			26			14			53
Income Before Income Taxes		47			104			303			406
Income Tax Expense		(19	)		(37	)		(114	)		(153	)
Net Income	$	28		$	67		$	189		$	253

Other Income, net

Other Income, net includes equity earnings of $4 million and $22 million for the three months ended September 30, 2007 and 2008, respectively.  Other Income, net includes equity earnings of $10 million and $46 million for the nine months ended September 30, 2007 and 2008, respectively.

Income Tax Expense

During the three months and nine months ended September 30, 2007, the effective tax rate was 41% and 38%, respectively. During the three months and nine months ended September 30, 2008, the effective tax rate was 36% and 38%, respectively.

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, 2007 and 2008 (in millions).

	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2008			2007			2008
Natural Gas Distribution	$	(8	)	$	(6	)	$	129		$	119
Competitive Natural Gas Sales and Services		4			35			56			36
Interstate Pipelines		70			55			166			227
Field Services		26			44			75			121
Other Operations		(1	)		1			(2	)		(2	)
Total Consolidated Operating Income	$	91		$	129		$	424		$	501

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 Businesses,” “— Risk Factors Associated with Our Consolidated Financial Condition” and “— Other Risks” in Item 1A of Part I of our 2007 Form 10-K and “Risk Factors” in Item 1A of Part II of this Quarterly Report on Form 10-Q.

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The following table provides summary data of our Natural Gas Distribution business segment for the three and nine months ended September 30, 2007 and 2008 (in millions, except throughput and customer data):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2008			2007		2008
Revenues	$	458		$	550		$	2,601	$	2,976
Expenses:
Natural gas		267			351			1,845		2,196
Operation and maintenance		139			139			421		436
Depreciation and amortization		38			40			114		118
Taxes other than income taxes		22			26			92		107
Total expenses		466			556			2,472		2,857
Operating Income (Loss)	$	(8	)	$	(6	)	$	129	$	119
Throughput (in Bcf):
Residential		12			13			118		117
Commercial and industrial		42			41			168		171
Total Throughput		54			54			286		288
Average number of customers:
Residential		2,910,041			2,937,618			2,927,122		2,956,500
Commercial and industrial		246,021			245,514			246,382		248,759
Total		3,156,062			3,183,132			3,173,504		3,205,259

Three months ended September 30, 2008 compared to three months ended September 30, 2007

Our Natural Gas Distribution business segment reported an operating loss of $6 million for the three months ended September 30, 2008 compared to an operating loss of $8 million for the three months ended September 30, 2007. Operating margin (revenues less the cost of gas) increased $8 million primarily as a result of rate increases ($2 million), growth ($1 million), with the addition of almost 26,000 customers since September 2007, increased other revenues ($3 million), and recovery of higher gross receipts taxes ($3 million), which are offset in other tax expense. Operation and maintenance expenses remained flat. Depreciation and amortization and taxes other than income taxes both increased primarily as a result of an increase in the investment in property, plant and equipment.

Nine months ended September 30, 2008 compared to nine months ended September 30, 2007

Our Natural Gas Distribution business segment reported operating income of $119 million for the nine months ended September 30, 2008 compared to operating income of $129 million for the nine months ended September 30, 2007. Operating margin improved $24 million primarily as a result of rate increases ($14 million), growth from the addition of nearly 26,000 customers since September 30, 2007 ($5 million),  and recovery of higher gross receipts taxes ($13 million) and energy-efficiency costs ($4 million), both of which are offset by the related expenses. These margin increases were partially offset by a combination of lower usage and the cost of the weather hedge ($12 million). Operation and maintenance expenses increased $15 million primarily as a result of increased bad debt expense ($4 million), higher customer-related costs and support services costs ($9 million) and increased costs of materials and supplies ($3 million), partially offset by lower employee benefits costs ($3 million). Depreciation and amortization and taxes other than income taxes both increased primarily as a result of an increase in the investment in property, plant and equipment.

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 Businesses,” “— Risk Factors Associated with Our Consolidated Financial Condition” and “— Other Risks” in Item 1A of Part I of our 2007 Form 10-K and “Risk Factors” in Item 1A of Part II of this Quarterly Report on Form 10-Q.

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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, 2007 and 2008 (in millions, except throughput and customer data):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2007		2008		2007		2008
Revenues	$	770	$	1,269	$	2,715	$	3,632
Expenses:
Natural gas		756		1,225		2,631		3,567
Operation and maintenance		7		8		23		26
Depreciation and amortization		3		1		4		2
Taxes other than income taxes		—		—		1		1
Total expenses		766		1,234		2,659		3,596
Operating Income	$	4	$	35	$	56	$	36
Throughput (in Bcf)		119		125		393		392
Average number of customers		6,976		9,245		7,014		8,974

Three months ended September 30, 2008 compared to three months ended September 30, 2007

Our Competitive Natural Gas Sales and Services business segment reported operating income of $35 million for the three months ended September 30, 2008 compared to operating income of $4 million for the three months ended September 30, 2007. The increase in operating income of $31 million in the third quarter of 2008 was primarily due to higher margins (revenues less natural gas costs) ($7 million) compared to the same period last year. In addition, the third quarter of 2008 included a positive mark-to-market for non-trading financial derivatives ($46 million) and a write-down of natural gas inventory to the lower of average cost or market ($24 million), compared to the gain from mark-to-market accounting ($2 million) and an inventory write-down ($5 million) for the same period of 2007. 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, 2008 compared to nine months ended September 30, 2007

Our Competitive Natural Gas Sales and Services business segment reported operating income of $36 million for the nine months ended September 30, 2008 compared to $56 million for the nine months ended September 30, 2007, a decrease in operating income of $20 million. The nine months ended September 30, 2008, included $24 million in inventory write-downs compared to $11 million in inventory write-downs for the same period of 2007.  Additionally, the nine months ended September 30, 2008, included $6 million in gains on sales of gas from previously written down inventory compared to $32 million for the same period of 2007.  Our Competitive Natural Gas Sales and Services business segment purchases and stores natural gas to meet certain future sales requirements and enters into derivative contracts to hedge the economic value of the future sales. The favorable mark-to-market accounting for non-trading financial derivatives for the first nine months of 2008 of $14 million versus the unfavorable mark-to-market accounting of $12 million for the same period in 2007 accounted for a net $26 million increase in operating margins. The additional decrease in operating income of $7 million for the first nine months ended September 30, 2008 compared to the same period last year was primarily due to a reduction in operating margin as basis and summer/winter spreads narrowed.

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 Businesses,” “— Risk Factors Associated with Our Consolidated Financial Condition” and “— Other Risks” in Item 1A of Part I of our 2007 Form 10-K and “Risk Factors” in Item 1A of Part II of this Quarterly Report on Form 10-Q.

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The following table provides summary data of our Interstate Pipelines business segment for the three and nine months ended September 30, 2007 and 2008 (in millions, except throughput data):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2007		2008		2007		2008
Revenues	$	137	$	143	$	348	$	468
Expenses:
Natural gas		27		24		55		97
Operation and maintenance		29		47		85		93
Depreciation and amortization		11		11		32		34
Taxes other than income taxes		—		6		10		17
Total expenses		67		88		182		241
Operating Income	$	70	$	55	$	166	$	227
Transportation throughput (in Bcf):		312		360		880		1,145

Three months ended September 30, 2008 compared to three months ended September 30, 2007

Our Interstate Pipelines business segment reported operating income of $55 million for the three months ended September 30, 2008 compared to $70 million for the three months ended September 30, 2007. The decrease in operating income is due to higher operation and maintenance expense ($18 million), including a write-down associated with pipeline assets removed from service ($7 million), and higher taxes other than income taxes ($6 million) largely due to tax refunds in 2007 related to certain state tax issues.  These increases in expenses are partially offset by higher margins (revenues less natural gas costs) primarily driven by the Carthage to Perryville pipeline ($7 million) and increased other transportation services ($6 million) which are partially offset by reduced margins on ancillary services ($4 million).

Nine months ended September 30, 2008 compared to nine months ended September 30, 2007

Our Interstate Pipelines business segment reported operating income of $227 million for the nine months ended September 30, 2008 compared to $166 million for the nine months ended September 30, 2007. The increase in operating income is primarily driven by increased margins (revenues less natural gas costs) on the Carthage to Perryville pipeline that went into service in May 2007 ($43 million), increased transportation and ancillary services ($35 million). These increases are partially offset by higher operation and maintenance expenses ($8 million), including a write-down associated with pipeline assets removed from service ($7 million) and a gain on the sale of two storage development projects ($18 million). Increased depreciation expense ($2 million) and higher taxes other than income taxes ($7 million), largely due to tax refunds in 2007, also offset increased margins.

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 Businesses,” “— Risk Factors Associated with Our Consolidated Financial Condition” and “— Other Risks” in Item 1A of Part I of our 2007 Form 10-K and “Risk Factors” in Item 1A of Part II of this Quarterly Report on Form 10-Q.

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The following table provides summary data of our Field Services business segment for the three and nine months ended September 30, 2007 and 2008 (in millions, except throughput data):

	Three Months Ended September 30,					Nine Months Ended September 30,
	2007			2008		2007			2008
Revenues	$	44		$	71	$	125		$	191
Expenses:
Natural gas		(2	)		5		(9	)		11
Operation and maintenance		17			19		49			48
Depreciation and amortization		2			3		8			9
Taxes other than income taxes		1			—		2			2
Total expenses		18			27		50			70
Operating Income	$	26		$	44	$	75		$	121
Gathering throughput (in Bcf):		104			109		297			311

Three months ended September 30, 2008 compared to three months ended September 30, 2007

Our Field Services business segment reported operating income of $44 million for the three months ended September 30, 2008 compared to $26 million for the three months ended September 30, 2007. The increase in operating income of $18 million was primarily driven by higher margins (revenues less natural gas costs) from gas gathering and ancillary services ($20 million), offset by increased operation and maintenance expenses ($2 million).

In addition, this business segment recorded equity income of $2 million and $4 million in the three months ended September 30, 2007 and 2008, respectively, from its 50 percent interest in a jointly-owned gas processing plant. These amounts are included in Other, net under the Other Income (Expense) caption.

Nine months ended September 30, 2008 compared to nine months ended September 30, 2007

Our Field Services business segment reported operating income of $121 million for the nine months ended September 30, 2008 compared to $75 million for the nine months ended September 30, 2007. The increase in operating income of $46 million resulted from higher margins (revenue less natural gas costs) from gas gathering, ancillary services and higher commodity prices ($35 million) and a one-time gain related to a settlement and contract buyout of one of our customers ($11 million).  Operating expenses remain constant from 2007 to 2008 with the increases in expenses associated with new assets and general cost increases offset by a one-time gain  related to the sale of assets recognized in the first quarter of 2008 ($6 million).

In addition, this business segment recorded equity income of $6 million and $12 million in the nine months ended September 30, 2007 and 2008, respectively, from its 50 percent interest in a jointly-owned gas processing 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 our 2007 Form 10-K and “Cautionary Statement Regarding Forward-Looking Information” and “Risk Factors” in this Quarterly Report on Form 10-Q.

LIQUIDITY AND CAPITAL RESOURCES

Our liquidity and capital requirements are affected primarily by our results of operations, capital expenditures, debt service requirements, and working capital needs. Our principal cash requirements for the remaining three months of 2008 are approximately $245 million of capital expenditures and an investment in or advances to SESH of approximately $30 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 in 2008. Cash needs or discretionary financing or

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refinancing may also result in the issuance of debt securities in the capital markets.  Issuances of debt in the capital markets may not, however, be available to us on acceptable terms.

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 against obligations under the remaining guaranties, RRI agreed to provide cash or letters of credit for our benefit, and undertook to use commercially reasonable efforts to extinguish the remaining guaranties. In December 2007, we, CenterPoint Energy and RRI amended that agreement and we released the letters of credit we held as security. Under the revised agreement RRI agreed to provide cash or new letters of credit to secure us against exposure under the remaining guaranties as calculated under the new agreement if and to the extent changes in market conditions exposed us to a risk of loss on those guaranties.

Our potential exposure under the guaranties relates to payment of demand charges related to transportation contracts. RRI continues to meet its obligations under the contracts, and, on the basis of current market conditions, we and CenterPoint Energy believe that additional security is not needed at this time. However, if RRI should fail to perform its obligations under the contracts or if RRI should fail to provide adequate security in the event market conditions change adversely, we would retain exposure to the counterparty under the guaranty.

Credit and Receivables Facilities.  As of October 31, 2008, we had the following facilities (in millions):

Date Executed	Company	Type of Facility	Size of Facility	Amount Utilized at October 31, 2008	Termination Date
June 29, 2007	CERC Corp.	Revolver	$ 950(1)	$ 919	June 29, 2012

________

(1) Lehman Brothers Bank, FSB, which has a $35 million participation in our credit facility stopped funding its commitments following the bankruptcy filing of its parent in September 2008, effectively causing a reduction to the total available capacity of $20 million under our facility from the amount shown in this column.

Our $950 million credit facility’s first drawn cost is London Interbank Offered Rate (LIBOR) plus 45 basis points based on our current credit ratings. The facility contains a debt to total capitalization covenant. 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 this 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 the credit facility are subject to acceleration upon the occurrence of events of default that we consider customary. We are currently in compliance with the various business and financial covenants contained in the credit facility.

Our receivables facility terminated on October 28, 2008. Advances under the receivables facility of $150 million were repaid upon termination of the facility.  We are currently negotiating a new receivables facility to replace the expired facility, but there can be no assurance that a new facility with acceptable terms can be obtained.

Our $950 million credit facility backstops a $950 million commercial paper program under which we began issuing commercial paper in February 2008. Our commercial paper is rated “P-3” by Moody’s Investor Services, Inc. (Moody’s), “A-2” by Standard and Poor’s Rating Services (S&P), a division of The McGraw-Hill Companies, and “F2” by Fitch, Inc. (Fitch). As a result of the credit ratings on our commercial paper program, we do not expect to be able to rely on the sale of commercial paper to fund all of our short-term borrowing requirements. We cannot assure you that these ratings, or the credit ratings set forth below in “— Impact on Liquidity of a Downgrade in Credit 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

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could have a material adverse impact on our ability to obtain short- and long-term financing, the cost of such financings and the execution of our commercial strategies.

Securities Registered with the SEC. As of October 31, 2008, we had a shelf registration statement covering $500 million principal amount of senior debt securities as a result of our registration statement filed in August 2008. 

Temporary Investments.  As of October 31, 2008, we had no external temporary investments.

Money Pool. We participate in a money pool through which we and certain of our affiliates can borrow or invest on a short-term basis. Funding needs are aggregated and external borrowing or investing is based on the net cash position. The net funding requirements of the money pool are expected to be met with borrowings under CenterPoint Energy’s revolving credit facility or the sale of CenterPoint Energy’s commercial paper. At October 31, 2008, we had borrowings of $113 million from the money pool. The money pool may not provide sufficient funds to meet our cash needs.

Impact on Liquidity of a Downgrade in Credit Ratings. As of October 31, 2008, Moody’s, S&P and Fitch had assigned the following credit ratings to our senior unsecured debt:

	Moody’s		S&P		Fitch
Company/Instrument	Rating	Outlook(1)	Rating	Outlook(2)	Rating	Outlook(3)
CERC Corp. Senior Unsecured Debt	Baa3	Stable	BBB	Stable	BBB	Stable

________

(1) A “stable” outlook from Moody’s indicates that Moody’s does not expect to put the rating on review for an upgrade or downgrade within 18 months from when the outlook was assigned or last affirmed.

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

(3) A “stable” outlook from Fitch encompasses a one-to-two year horizon as to the likely ratings direction.

In October 2008, Moody’s affirmed the credit ratings and stable outlook for our senior unsecured debt.

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 of our Natural Gas Distribution and Competitive Natural Gas Sales and Services business segments.

CenterPoint Energy Services, Inc. (CES), a wholly owned subsidiary 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, 2008, the amount posted as collateral amounted to approximately $143 million. Should the credit ratings of CERC Corp. (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, 2008, unsecured credit limits extended to CES by counterparties aggregate $175 million; however, utilized credit capacity is significantly lower. In addition, we 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, CERC Corp. advanced funds to the joint venture for its 50% share of the cost to construct the pipeline. As of September 30, 2008, our subsidiaries have

26

advanced approximately $582 million to SESH, of which $266 million was in the form of an equity contribution and $316 million was in the form of a loan.

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 or any of our significant subsidiaries will cause a default. In addition, four outstanding series of CenterPoint Energy’s senior notes, aggregating $950 million in principal amount as of September 30, 2008, provide that 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. A default by CenterPoint Energy would not trigger a default under our subsidiaries’ debt instruments or bank credit facilities.

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

Pension Plan Costs.  Substantially all of our employees participate in CenterPoint Energy’s qualified non-contributory defined benefit pension plan.  Net periodic pension costs will likely increase in 2009 due to decreases in CenterPoint Energy’s pension plan assets as a result of recent declines in global equity and fixed income markets.  Pension expense increases approximately $5 million for every 5% decline in plan assets.

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 and our subsidiaries, including indemnity obligations, or in connection with the contractual obligations to a third party 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 the timing of recovery of such restoration costs; and

· various other risks identified in “Risk Factors” in Item 1A of our 2007 Form 10-K and “Risk Factors” in Item 1A of Part II of this Quarterly Report on Form 10-Q.

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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%.

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

NEW ACCOUNTING PRONOUNCEMENTS

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

Item 4T.             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, 2008 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, 2008 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

PART II.  OTHER INFORMATION

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 our 2007 Form 10-K.

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 our 2007 Form 10-K.

Item 1A.             RISK FACTORS

Other than with respect to the risk factor set forth below, there have been no material changes from the risk factors disclosed in our 2007 Form 10-K.

The global financial crisis may have impacts on our business and financial condition that we currently cannot predict.

The continued credit crisis and related turmoil in the global financial system may have an impact on our business and our financial condition.  Our ability to access the capital markets may be severely restricted at a time when we would like, or need, to access those markets, which could have an impact on our flexibility to react to changing economic and business conditions. In addition, the cost of debt financing may be materially adversely impacted by these market conditions.  With respect to our existing debt arrangements, Lehman Brothers Bank, FSB, which has a $35 million participation in our credit facility, stopped funding its commitments following the bankruptcy filing of its parent in September 2008, effectively causing a $20 million reduction to the total available capacity under our facility. The credit crisis could have an impact on our remaining lenders or our customers,

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causing them to fail to meet their obligations to us.  Additionally, the crisis could have a broader impact on business in general in ways that could lead to reduced gas usage, which could have a negative impact on our revenues.

Item 5.                OTHER INFORMATION

Our ratio of earnings to fixed charges for the nine months ended September 30, 2007 and 2008 was 2.87 and 3.47, 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.

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.

Exhibit Number		Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference
3.1.1	—	Certificate of Incorporation of RERC Corp.	Form 10-K for the year ended December 31, 1997	1-13265	3(a)(1)
3.1.2	—	Certificate of Merger merging former NorAm Energy Corp. with and into HI Merger, Inc. dated August 6, 1997	Form 10-K for the year ended December 31, 1997	1-13265	3(a)(2)
3.1.3	—	Certificate of Amendment changing the name to Reliant Energy Resources Corp.	Form 10-K for the year ended December 31, 1998	1-13265	3(a)(3)
3.1.4	—	Certificate of Amendment changing the name to CenterPoint Energy Resources Corp.	Form 10-Q for the quarter ended September 30, 2003	1-13265	3(a)(4)
3.2	—	Bylaws of RERC Corp.	Form 10-K for the year ended December 31, 1997	1-13265	3(b)
4.1	—	$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	CERC Corp.’s Form 10-Q for the quarter ended September 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	Form 8-K dated February 5, 1998	1-13265	4.1
4.3	—	Supplemental Indenture No. 13 to Exhibit 4.8, dated as of May 15, 2007, providing for the issuance of CERC Corp.’s 6.00% Senior Notes due 2018	CenterPoint Energy’s Form 10-Q for the quarter ended September 30, 2008	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

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Exhibit Number		Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference
+99.1	—	Items incorporated by reference from the CERC Corp. Form 10-K. Item 1A “—Risk Factors.”

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SIGNATURES

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

CENTERPOINT ENERGY RESOURCES CORP.

By:  /s/ Walter L. Fitzgerald

Walter L. Fitzgerald

Senior Vice President and Chief Accounting Officer

Date:  November 10, 2008

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Index to Exhibits

The following exhibits are filed herewith:

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

Exhibit Number		Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference
3.1.1	—	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 September 30, 2003	1-13265	3(a)(4)
3.2	—	Bylaws of RERC Corp.	Form 10-K for the year ended December 31, 1997	1-13265	3(b)
4.1	—	$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	CERC Corp.’s Form 10-Q for the quarter ended September 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	Form 8-K dated February 5, 1998	1-13265	4.1
4.3	—	Supplemental Indenture No. 13 to Exhibit 4.8, dated as of May 15, 2007, providing for the issuance of CERC Corp.’s 6.00% Senior Notes due 2018	CenterPoint Energy’s Form 10-Q for the quarter ended September 30, 2008	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.”

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