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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

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

FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2008

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 July 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.

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CENTERPOINT ENERGY RESOURCES CORP.

QUARTERLY REPORT ON FORM 10-Q

FOR THE QUARTER ENDED JUNE 30, 2008

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PART I.	FINANCIAL INFORMATION

Item 1.	Financial Statements	1

	Condensed Statements of Consolidated Income
	Three and Six Months Ended June 30, 2007 and 2008 (unaudited)	1

	Condensed Consolidated Balance Sheets
	December 31, 2007 and June 30, 2008 (unaudited)	2

	Condensed Statements of Consolidated Cash Flows
	Six Months Ended June 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	18

Item 4T.	Controls and Procedures	26

PART II.	OTHER INFORMATION

Item 1.	Legal Proceedings	26

Item 1A.	Risk Factors	27

Item 5.	Other Information	27

Item 6.	Exhibits	27

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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 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, and other reports we file from time to time with the Securities and Exchange Commission.

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

iii

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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 June 30,						Six Months Ended June 30,
	2007			2008			2007			2008

Revenues	$	1,566		$	2,157		$	4,263		$	5,109

Expenses:
Natural gas		1,208			1,750			3,358			4,143
Operation and maintenance		188			184			386			389
Depreciation and amortization		52			55			103			109
Taxes other than income taxes		35			38			83			96
Total		1,483			2,027			3,930			4,737

Operating Income		83			130			333			372

Other Income (Expense): Interest and other finance charges		(45	)		(49	)		(84	)		(97	)
Other, net		4			16			7			27
Total		(41	)		(33	)		(77	)		(70	)

Income Before Income Taxes		42			97			256			302
Income tax expense		(12	)		(37	)		(95	)		(116	)
Net Income	$	30		$	60		$	161		$	186

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		June 30, 2008
Current Assets:
Cash and cash equivalents	$	1	$	30
Accounts and notes receivable, net		732		780
Accrued unbilled revenue		456		156
Accounts and notes receivable – affiliated companies		82		16
Materials and supplies		35		43
Natural gas inventory		395		321
Non-trading derivative assets		38		102
Deferred tax asset		40		6
Prepaid expenses and other current assets		235		255
Total current assets		2,014		1,709

Property, Plant and Equipment:
Property, plant and equipment		5,837		6,034
Less accumulated depreciation and amortization		806		877
Property, plant and equipment, net		5,031		5,157

Other Assets:
Goodwill		1,696		1,696
Non-trading derivative assets		11		96
Notes receivable from unconsolidated affiliates		148		244
Other		234		403
Total other assets		2,089		2,439

Total Assets	$	9,134	$	9,305

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 — (Continued)

(Millions of Dollars)

(Unaudited)

LIABILITIES AND STOCKHOLDER’S EQUITY

	December 31, 2007		June 30, 2008
Current Liabilities:
Short-term borrowings	$	232	$	200
Current portion of long-term debt		307		7
Accounts payable		661		671
Accounts and notes payable — affiliated companies		144		62
Taxes accrued		118		95
Interest accrued		59		51
Customer deposits		59		57
Non-trading derivative liabilities		60		30
Other		186		388
Total current liabilities		1,826		1,561

Other Liabilities:
Accumulated deferred income taxes, net		778		763
Non-trading derivative liabilities		14		9
Benefit obligations		116		113
Regulatory liabilities		474		494
Other		167		243
Total other liabilities		1,549		1,622

Long-term Debt		2,645		2,826

Commitments and Contingencies (Note 10)

Stockholder’s Equity:
Common stock		—		—
Paid-in capital		2,406		2,406
Retained earnings		692		878
Accumulated other comprehensive income		16		12
Total stockholder’s equity		3,114		3,296

Total Liabilities and Stockholder’s Equity	$	9,134	$	9,305

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 STATEMENTS OF CONSOLIDATED CASH FLOWS

(Millions of Dollars)

(Unaudited)

	Six Months Ended June 30,
	2007			2008
Cash Flows from Operating Activities:
Net income	$	161		$	186
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		103			109
Amortization of deferred financing costs		4			4
Deferred income taxes		23			14
Write-down of natural gas inventory		6			—
Changes in other assets and liabilities:
Accounts receivable and unbilled revenues, net		446			252
Accounts receivable/payable, affiliates		12			51
Inventory		8			66
Accounts payable		(277	)		20
Fuel cost over recovery		(39	)		3
Interest and taxes accrued		(33	)		(31	)
Non-trading derivatives, net		12			27
Margin deposits, net		80			95
Other current assets		(112	)		(63	)
Other current liabilities		(43	)		94
Other assets		(12	)		(20	)
Other liabilities		(65	)		(73	)
Other, net		(1	)		(26	)
Net cash provided by operating activities		273			708

Cash Flows from Investing Activities:
Capital expenditures		(419	)		(222	)
Increase in notes receivable from affiliates, net		—			(96	)
Investment in unconsolidated affiliates		(34	)		(162	)
Other, net		(13	)		19
Net cash used in investing activities		(466	)		(461	)

Cash Flows from Financing Activities:
Increase (decrease) in short-term borrowings, net		38			(32	)
Long-term revolving credit facility, net		—			(150	)
Proceeds from commercial paper, net		—			40
Proceeds from long-term debt		150			300
Payments of long-term debt		(7	)		(307	)
Increase (decrease) in notes payable to affiliates		11			(67	)
Debt issuance costs		(2	)		(2	)
Other, net		2			—
Net cash provided by (used in) financing activities		192			(218	)

Net Increase (Decrease) in Cash and Cash Equivalents		(1	)		29
Cash and Cash Equivalents at Beginning of Period		5			1
Cash and Cash Equivalents at End of Period	$	4		$	30

Supplemental Disclosure of Cash Flow Information:
Cash Payments:
Interest, net of capitalized interest	$	85		$	104
Income taxes		167			109

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

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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.

(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 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

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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. 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 June 30, 2008, and indicates the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair value.

	Quoted Prices in			Significant Other			Significant
	Active Markets			Observable			Unobservable						Balance
	for Identical Assets			Inputs			Inputs			Netting			as of
	(Level 1)			(Level 2)			(Level 3)			Adjustments (1)			June 30, 2008
	(in millions)
Assets
Corporate equities		$	1		$	—		$	—	$	—			$	1
Investments			11			—			—		—				11
Derivative assets			62			266			14		(144	)			198
Total assets		$	74		$	266		$	14	$	(144	)		$	210
Liabilities
Derivative liabilities		$	70		$	42		$	8	$	(81	)		$	39
Total liabilities		$	70		$	42		$	8	$	(81	)		$	39

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(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 June 30, 2008:

	Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Derivative assets and liabilities, net
	(in millions)
Beginning balance as of April 1, 2008	$	2
Total gains or losses (realized and unrealized):
Included in earnings		3
Purchases, sales, other settlements, net		1
Ending balance as of June 30, 2008	$	6
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	$	3

	Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Derivative assets and liabilities, net
	(in millions)
Beginning balance as of January 1, 2008	$	(3	)
Total gains or losses (realized and unrealized):
Included in earnings		9
Ending balance as of June 30, 2008	$	6
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

In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (SFAS No. 162), which identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements that are presented in conformity with GAAP. The Company plans to adopt SFAS No. 162 when it becomes effective. The adoption of SFAS No. 162 will not have an impact on the Company’s consolidated financial position or results of operations.

(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 June 30,				Six Months Ended June 30,
	2007		2008		2007		2008
	(in millions)
Interest cost	$	2	$	2	$	4	$	4
Amortization of prior service cost		1		1		1		1
Net periodic cost	$	3	$	3	$	5	$	5

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The Company expects to contribute approximately $14 million to CenterPoint Energy’s postretirement benefits plan in 2008, of which $4 million and $7 million, respectively, was contributed during the three and six months ended June 30, 2008.

(4) Regulatory Matters

Texas. In March 2008, the Company’s natural gas distribution business (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, nine of those 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 hearing on this issue is scheduled to begin in August 2008, with a final decision due no later than October 2008. In July 2008, Gas Operations reached a settlement agreement with the GCCC. The settlement agreement, if implemented across the entire Texas Coast service territory, would allow Gas Operations an additional $3.4 million in annual revenue and provides 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. By virtue of an agreement with the Texas Coast cities that have already implemented Gas Operations’ rate request, the settled rates will apply to all cities in the Texas Coast service territory except the nine TCUC cities and the environs whose rates will be established by the Railroad Commission. However, if the Railroad Commission approves lower rates than the settled rates, rates in the entire Texas Coast service territory would be conformed to the lower rates.

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. No prediction can be made as to the ultimate outcome of this matter.

(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, “Accounting for Derivative Instruments and Hedging Activities” (SFAS No. 133). The objective of these derivative instruments is to hedge the price risk associated with natural gas purchases and sales to reduce cash flow variability related to meeting the Company’s wholesale and retail customer obligations. During each of the three and six months ended June 30, 2007 and 2008, hedge ineffectiveness resulted in a gain or loss of 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 income 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

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Statements of Consolidated Cash Flows in the same category as the item being hedged. As of June 30, 2008, the Company expects $2 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 June 30, 2007, the Company recorded increased natural gas expense from unrealized net losses of $6 million. During the three months ended June 30, 2008, the Company recorded increased revenues from unrealized net gains of $6 million and increased natural gas expense from unrealized net losses of $16 million, a net unrealized loss of $10 million. During the six months ended June 30, 2007, the Company recorded increased natural gas expense from unrealized net losses of $14 million. During the six months ended June 30, 2008, the Company recorded decreased revenues from unrealized net losses of $15 million and increased natural gas expense from unrealized net losses of $17 million, a net unrealized loss of $32 million.

Weather Derivatives. The Company has weather normalization or other rate mechanisms that mitigate the impact of weather in Arkansas, Louisiana and Oklahoma. The remaining Gas Operations jurisdictions, Minnesota, Mississippi and 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 six months ended June 30, 2008, the Company recognized losses of $2 million and $13 million, respectively, related to these swaps. This 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 June 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

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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 June 30,				For the Six Months Ended June 30,
	2007		2008		2007			2008
	(in millions)
Net income	$	30	$	60	$	161		$	186
Other comprehensive income (loss):
SFAS No. 158 adjustment (net of tax of $-0-)		—		—		1			—
Net deferred gain from cash flow hedges (net of tax of $3 and $3)		5		—		5			—
Reclassification of deferred gain from cash flow hedges realized in net income (net of tax of $17 and $2)		—		—		(27	)		(4	)
Other comprehensive income (loss)		5		—		(21	)		(4	)
Comprehensive income	$	35	$	60	$	140		$	182

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

	December 31, 2007		June 30, 2008
	(in millions)
SFAS No. 158 adjustment	$	11	$	11
Net deferred gain from cash flow hedges		5		1
Total accumulated other comprehensive income	$	16	$	12

(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 June 30, 2008, the Company had borrowings from the money pool of $67 million and $-0- million, respectively.

For each of the three month periods ended June 30, 2007 and 2008, the Company had net interest expense related to affiliate borrowings of less than $1 million. For each of the six month periods ended June 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 $25 million and $35 million for the three months ended June 30, 2007 and 2008, respectively, and $65 million and $70 million for the six months ended June 30, 2007 and 2008, respectively, and are included primarily in operation and maintenance expenses.

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

(a) Short-term Borrowings

In October 2007, the Company amended its receivables facility and extended the termination date to October 28, 2008. The facility size ranges from $150 million to $375 million during the period from September 30, 2007 to the October 28, 2008 termination date. The variable size of the facility was designed to track the seasonal pattern of receivables in the Company’s natural gas businesses. At June 30, 2008, the facility size was $200 million. As of

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December 31, 2007 and June 30, 2008, $232 million and $200 million, respectively, was advanced for the purchase of receivables under the Company’s receivables facility.

(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 approximately $30 million of borrowings under its senior unsecured revolving credit facility, which terminates in 2012, and used the remainder of the net proceeds from the offering to repay borrowings from its affiliates.

Revolving Credit Facility. As of December 31, 2007 and June 30, 2008, the Company had borrowings of $150 million and $-0-, respectively, and $-0- and $40 million of commercial paper outstanding, respectively, under its $950 million credit facility. The Company was in compliance with all debt covenants as of June 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 June 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 June 30, 2008, minimum payment obligations for natural gas supply commitments are approximately $513 million for the remaining six months in 2008, $594 million in 2009, $319 million in 2010, $305 million in 2011, $294 million in 2012 and $1.3 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, punitive damages, injunctive relief, interest due, civil penalties and fines, costs of suit 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 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

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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 and August 2008, the plaintiffs in nine of the federal court cases agreed to dismiss CenterPoint Energy from those cases. CenterPoint Energy remains a defendant in one suit pending in Nevada state court in Clark County. CenterPoint Energy Services, Inc. (CES), a wholly owned subsidiary of the Company, operating in our Competitive Natural Gas Sales and Services business segment, is a defendant in another suit consolidated under multidistrict litigation rules in federal district court in Nevada. CenterPoint Energy and the Company believe that none of the CenterPoint Energy entities is a proper defendant in the remaining cases and will continue to seek 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 the Company, CenterPoint Energy, Entex Gas Marketing Company (EGMC), and certain non-affiliated companies alleging fraud, violations of the Texas Deceptive Trade Practices Act, violations of the Texas Utilities Code, civil conspiracy and violations of the Texas Free Enterprise and Antitrust Act with respect to rates charged to certain consumers of natural gas in the State of Texas. The plaintiffs initially sought certification of a class of Texas ratepayers, but subsequently dropped their request for class certification. The plaintiffs later added as defendants CenterPoint Energy Marketing Inc., CenterPoint Energy Pipeline Services, Inc. (CEPS), and certain other subsidiaries of the Company, and other non-affiliated companies. In February 2005, the case was removed to federal district court in Houston, Texas, and in March 2005, the plaintiffs voluntarily dismissed the case and agreed not to refile the claims asserted unless the Miller County case described below is not certified as a class action or is later decertified.

In October 2004, a lawsuit was filed by certain ratepayers of the Company in Texas and Arkansas in circuit court in Miller County, Arkansas against the Company, CenterPoint Energy, EGMC, CenterPoint Energy Gas Transmission Company (CEGT), CenterPoint Energy Field Services (CEFS), CEPS, Mississippi River Transmission Corp. (MRT) and other non-affiliated companies alleging fraud, unjust enrichment and civil conspiracy with respect to rates charged to certain consumers of natural gas in Arkansas, Louisiana, Minnesota, Mississippi, Oklahoma and Texas. Subsequently, the plaintiffs dropped CEGT and MRT as defendants. Although the plaintiffs in the Miller

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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, the Company, CenterPoint Energy, EGMC and other defendants in the Miller County case filed a petition in a district court in Travis County, Texas seeking a determination that the Railroad Commission has original exclusive jurisdiction over the Texas claims asserted in the Miller County case. In October 2007, CEFS and CEPS were joined as plaintiffs to the Travis County case.

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

Storage Facility Litigation. In February 2007, an Oklahoma district court in Coal County, Oklahoma, granted a summary judgment against CEGT in a case, Deka Exploration, Inc. v. CenterPoint Energy, filed by holders of oil and gas leaseholds and some mineral interest owners in lands underlying CEGT’s Chiles Dome Storage Facility. The dispute concerns “native gas” that may have been in the Wapanucka formation underlying the Chiles Dome facility when that facility was constructed in 1979 by 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.

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

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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 June 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 June 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.

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.

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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 six months ended June 30, 2007, the effective tax rate was 29% and 37%, respectively. During each of the three months and six months ended June 30, 2008, the effective tax rate was 39%. The most significant item affecting the comparability of the effective tax rate for the three months ended June 30, 2007 is a favorable state audit settlement.

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 June 30, 2008 (in millions):

	December 31, 2007			June 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.

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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.

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

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

	For the Three Months Ended June 30, 2007
	Revenues from External Customers		Net Intersegment Revenues			Operating Income (Loss)
Natural Gas Distribution	$	573	$	3		$	8
Competitive Natural Gas Sales and Services		874		7			(4	)
Interstate Pipelines		88		33			52
Field Services		30		12			27
Other Operations		1		—			—
Eliminations		—		(55	)		—
Consolidated	$	1,566	$	—		$	83

	For the Three Months Ended June 30, 2008
	Revenues from External Customers			Net Intersegment Revenues			Operating Income (Loss)
Natural Gas Distribution	$	724		$	2		$	4
Competitive Natural Gas Sales and Services		1,234			9			(5	)
Interstate Pipelines		150			42			101	(1)
Field Services		50			12			32
Other Operations		(1	)		—			(2	)
Eliminations		—			(65	)		—
Consolidated	$	2,157		$	—		$	130

	For the Six Months Ended June 30, 2007
	Revenues from External Customers		Net Intersegment Revenues			Operating Income (Loss)			Total Assets as of December 31, 2007
Natural Gas Distribution	$	2,137	$	6		$	137		$	4,332
Competitive Natural Gas Sales and Services		1,921		24			52			1,221
Interstate Pipelines		147		64			96			3,007
Field Services		58		23			49			669
Other Operations		—		—			(1	)		670
Eliminations		—		(117	)		—			(765	)
Consolidated	$	4,263	$	—		$	333		$	9,134

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	For the Six Months Ended June 30, 2008
	Revenues from External Customers		Net Intersegment Revenues			Operating Income (Loss)			Total Assets as of June 30, 2008
Natural Gas Distribution	$	2,421	$	5		$	125		$	4,213
Competitive Natural Gas Sales and Services		2,343		20			1			1,498
Interstate Pipelines		241		84			172	(1)		3,464
Field Services		104		16			77	(2)		759
Other Operations		—		—			(3	)		464
Eliminations		—		(125	)		—			(1,093	)
Consolidated	$	5,109	$	—		$	372		$	9,305

(1)	Included in operating income of Interstate Pipelines for the three and six months ended June 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 six months ended June 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 six months ended June 30, 2007 and the three and six months ended June 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

Debt Financing Transactions

In May 2008, we 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, we repaid approximately $30 million of borrowings under our senior unsecured revolving credit facility, which terminates in 2012, and used the remainder of the net proceeds from the offering to repay borrowings from our affiliates.

Interstate Pipeline Expansion

In May 2007, CenterPoint Energy Gas Transmission (CEGT), our wholly owned subsidiary, received Federal Energy Regulatory Commission (FERC) approval for the third phase of its Carthage to Perryville pipeline project, a 172-mile, 42-inch diameter pipeline and related compression facilities for the transportation of gas from Carthage, Texas to CEGT’s Perryville hub in northeast Louisiana, to expand capacity of the pipeline to 1.5 billion cubic feet (Bcf) per day by adding additional compression and operating at higher pressures. In July 2007, CEGT received approval from the Pipeline and Hazardous Materials Administration (PHMSA) to increase the maximum allowable operating pressure. The PHMSA’s approval contained certain conditions and requirements. In March 2008, CEGT met these conditions and gave notice to PHMSA that it would be increasing the pressure in 30 days. In April 2008, CEGT raised the maximum allowable pressure and concurrently placed the phase three expansion in service. The Carthage to Perryville pipeline can now operate at up to 1.5 Bcf per day.

Effective April 1, 2008, Mississippi River Transmission Corp., our wholly owned subsidiary, signed a 5-year extension of its firm transportation and storage contracts with Laclede Gas Company (Laclede). In 2007, approximately 10% of Interstate Pipelines’ operating revenues was attributable to services provided to Laclede.

Southeast Supply Header. Construction continues on the Southeast Supply Header (SESH) pipeline project which began in November 2007. SESH expects to complete construction of the pipeline in the second half of 2008. We have experienced increased costs and now expect SESH’s net costs after Southern Natural Gas’ contribution to be approximately $1.2 billion, our share of which we expect to be approximately $600 million.

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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.

The following table sets forth our consolidated results of operations for the three and six months ended June 30, 2007 and 2008, followed by a discussion of the results of operations by business segment based on operating income.

	Three Months Ended June 30,						Six Months Ended June 30,
	2007			2008			2007			2008
	(in millions)
Revenues	$	1,566		$	2,157		$	4,263		$	5,109
Expenses:
Natural gas		1,208			1,750			3,358			4,143
Operation and maintenance		188			184			386			389
Depreciation and amortization		52			55			103			109
Taxes other than income taxes		35			38			83			96
Total Expenses		1,483			2,027			3,930			4,737
Operating Income		83			130			333			372
Interest and Other Finance Charges		(45	)		(49	)		(84	)		(97	)
Other Income, net		4			16			7			27
Income Before Income Taxes		42			97			256			302
Income Tax Expense		(12	)		(37	)		(95	)		(116	)
Net Income	$	30		$	60		$	161		$	186

Income Tax Expense

RESULTS OF OPERATIONS BY BUSINESS SEGMENT

The following table presents operating income (loss) for each of our business segments for the three and six months ended June 30, 2007 and 2008 (in millions).

	Three Months Ended June 30,						Six Months Ended June 30,
	2007			2008			2007			2008
Natural Gas Distribution	$	8		$	4		$	137		$	125
Competitive Natural Gas Sales and Services		(4	)		(5	)		52			1
Interstate Pipelines		52			101			96			172
Field Services		27			32			49			77
Other Operations		—			(2	)		(1	)		(3	)
Total Consolidated Operating Income	$	83		$	130		$	333		$	372

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Natural Gas Distribution

For information regarding factors that may affect the future results of operations of our Natural Gas Distribution business segment, please read “Risk Factors — Risk Factors 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.

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2007		2008		2007		2008
Revenues	$	576	$	726	$	2,143	$	2,426
Expenses:
Natural gas		366		512		1,578		1,845
Operation and maintenance		135		141		282		297
Depreciation and amortization		38		39		76		78
Taxes other than income taxes		29		30		70		81
Total expenses		568		722		2,006		2,301
Operating Income	$	8	$	4	$	137	$	125

Throughput (in Bcf):
Residential		20		20		106		104
Commercial and industrial		44		47		126		130
Total Throughput		64		67		232		234

Average number of customers:
Residential		2,925,120		2,956,291		2,935,661		2,965,941
Commercial and industrial		247,550		249,776		246,564		250,382
Total		3,172,670		3,206,067		3,182,225		3,216,323

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

Our Natural Gas Distribution business segment reported operating income of $4 million for the three months ended June 30, 2008 compared to operating income of $8 million for the three months ended June 30, 2007. Operating margin (revenues less the cost of gas) increased $4 million primarily as a result of rate increases ($3 million), customer growth ($1 million) from the addition of nearly 34,000 customers since June 30, 2007, and recovery of higher gross receipts taxes ($2 million), which are offset in other tax expense, partially offset by weather and the cost of the weather hedge ($2 million). Operation and maintenance expenses increased $6 million primarily as a result of increased bad debt and collection efforts ($4 million) and higher customer-related costs and support services ($7 million), partially offset by lower employee-related costs ($4 million).

Six months ended June 30, 2008 compared to six months ended June 30, 2007

Our Natural Gas Distribution business segment reported operating income of $125 million for the six months ended June 30, 2008 compared to operating income of $137 million for the six months ended June 30, 2007. Operating margin improved $16 million primarily as a result of rate increases ($8 million), growth from the addition of nearly 34,000 customers since June 30, 2007 ($3 million), recovery of higher gross receipts taxes ($10 million) and energy-efficiency costs ($4 million), both of which are offset by the related expenses. These margin increases were partially offset by lower use per customer and the cost of the weather hedge ($16 million). Operation and maintenance expenses increased $15 million primarily as a result of increased bad debt and collection efforts ($6 million), higher customer-related costs and support services ($7 million) and increased costs of materials and supplies ($2 million), partially offset by lower employee-related costs ($6 million).

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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.

The following table provides summary data of our Competitive Natural Gas Sales and Services business segment for the three and six months ended June 30, 2007 and 2008 (in millions, except throughput and customer data):

	Three Months Ended June 30,						Six Months Ended June 30,
	2007			2008			2007		2008
Revenues	$	881		$	1,243		$	1,945	$	2,363
Expenses:
Natural gas		877			1,237			1,875		2,342
Operation and maintenance		7			10			16		18
Depreciation and amortization		1			—			1		1
Taxes other than income taxes		—			1			1		1
Total expenses		885			1,248			1,893		2,362
Operating Income (Loss)	$	(4	)	$	(5	)	$	52	$	1

Throughput (in Bcf)		120			129			275		267

Average number of customers		7,077			9,186			7,032		8,840

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

Our Competitive Natural Gas Sales and Services business segment reported an operating loss of $5 million for the three months ended June 30, 2008 compared to an operating loss of $4 million for the three months ended June 30, 2007. The decrease in operating income of $1 million in the second quarter of 2008 was primarily due to an increase in operating expenses, excluding natural gas, of $3 million compared to the same period last year. The second quarter of 2008 included charges of $10 million resulting from mark-to-market accounting for derivatives used to lock in economic margins of certain forward natural gas sales compared to mark-to-market charges of $6 million for the same period of 2007.

Six months ended June 30, 2008 compared to six months ended June 30, 2007

Our Competitive Natural Gas Sales and Services business segment reported operating income of $1 million for the six months ended June 30, 2008 compared to $52 million for the six months ended June 30, 2007. The decrease in operating income of $51 million was due in part to higher operating margins (revenues less natural gas costs) in 2007 related to sales of gas from inventory that was written down to the lower of cost or market in 2006 of $18 million. 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 unfavorable mark-to-market accounting for non-trading financial derivatives for the first six months of 2008 of $32 million versus $14 million for the same period in 2007 accounted for a further net $18 million decrease in operating margins. The additional decrease in operating income of $15 million for the first six months ended June 30, 2008 compared to the same period last year was primarily due to a reduction in 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.

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2007		2008		2007		2008
Revenues	$	121	$	192	$	211	$	325
Expenses:
Natural gas		24		58		28		73
Operation and maintenance		29		16		56		46
Depreciation and amortization		11		11		21		23
Taxes other than income taxes		5		6		10		11
Total expenses		69		91		115		153
Operating Income	$	52	$	101	$	96	$	172

Transportation throughput (in Bcf)		274		361		568		785

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

Our Interstate Pipeline business segment reported operating income of $101 million for the three months ended June 30, 2008 compared to $52 million for the three months ended June 30, 2007. The increase in operating income was primarily from the Carthage to Perryville pipeline that went into service in May 2007 ($12 million), increased transportation and ancillary services ($22 million) and a gain on the sale of two storage development projects ($18 million), partially offset by increased operating expenses ($4 million).

Six months ended June 30, 2008 compared to six months ended June 30, 2007

Our Interstate Pipeline business segment reported operating income of $172 million for the six months ended June 30, 2008 compared to $96 million for the six months ended June 30, 2007. The increase in operating income was primarily due to operating the Carthage to Perryville pipeline Phase I and II for six months and Phase III for three months ($31 million), increased transportation and ancillary services ($32 million) and a gain on the sale of two storage development projects ($18 million), partially offset by an increase in operating expenses ($5 million).

Field Services

For information regarding factors that may affect the future results of operations of our Field Services business segment, please read “Risk Factors — Risk Factors Affecting Our Businesses,” “— Risk Factors Associated with Our Consolidated Financial Condition” and “— Other Risks” in Item 1A of Part I of our 2007 Form 10-K.

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

	Three Months Ended June 30,					Six Months Ended June 30,
	2007			2008		2007			2008
Revenues	$	42		$	62	$	81		$	120
Expenses:
Natural gas		(4	)		8		(7	)		6
Operation and maintenance		16			18		32			29
Depreciation and amortization		3			3		6			6
Taxes other than income taxes		—			1		1			2
Total expenses		15			30		32			43
Operating Income	$	27		$	32	$	49		$	77

Gathering throughput (in Bcf)		100			104		193			202

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

Our Field Services business segment reported operating income of $32 million for the three months ended June 30, 2008 compared to $27 million for the three months ended June 30, 2007. The increase in operating income

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of $5 million was primarily driven by increased revenues from gas gathering and ancillary services and higher commodity prices, partially offset by increased operating expenses associated with new assets and general cost increases.

In addition, this business segment recorded equity income of $2 million and $4 million in the three months ended June 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.

Six months ended June 30, 2008 compared to six months ended June 30, 2007

Our Field Services business segment reported operating income of $77 million for the six months ended June 30, 2008 compared to $49 million for the six months ended June 30, 2007. The increase in operating income of $28 million was primarily driven by a one-time gain ($11 million) related to a settlement and contract buyout of one of our customers and a one-time gain ($6 million) related to the sale of assets, both recognized in the first quarter of 2008. In addition to these one-time items, increased revenues from gas gathering and ancillary services and higher commodity prices were partially offset by increased operating expenses associated with new assets and general cost increases.

In addition, this business segment recorded equity income of $4 million and $8 million in the six months ended June 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.”

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 six months of 2008 are approximately $505 million of capital expenditures and an investment in or advances to SESH of approximately $155 million.

We expect that borrowings under our credit facility, the proceeds from the May 2008 issuance of $300 million of our senior notes (discussed below) and 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 refinancing may also result in the issuance of debt securities in the capital markets.

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,

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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 July 31, 2008, we had the following facilities (in millions):

Date Executed

Company

Type of Facility

Size of Facility

Amount Utilized at

July 31, 2008

Termination Date

June 29, 2007

CERC Corp.

Revolver

950

172

(1)

June 29, 2012

October 30, 2007

CERC

Receivables

200

180

October 28, 2008

________

(1)	Includes $150 million of borrowings under our credit facility and $22 million of outstanding commercial paper supported by our credit facility.

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 each of the credit facilities 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 respective receivables and credit facilities.

Our $950 million credit facility backstops a $950 million commercial paper program under which we began issuing commercial paper in February 2008. As of June 30, 2008, there was $40 million of commercial paper outstanding. 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 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 June 30, 2008, we had a shelf registration statement covering $100 million principal amount of senior debt securities.

Temporary Investments. As of June 30, 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 July 31, 2008, we had no borrowings 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 July 31, 2008, Moody’s, S&P and Fitch had assigned the following credit ratings to our senior unsecured debt:

Moody’s		S&P		Fitch
Rating	Outlook(1)	Rating	Outlook(2)	Rating	Outlook(3)
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.

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(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.

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 June 30, 2008, the amount posted as collateral amounted to approximately $32 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 June 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, we have committed that we will advance funds to the joint venture or cause funds to be advanced for our 50% share of the cost to construct the pipeline. We also agreed to provide a letter of credit in an amount up to $400 million for our share of funds that have not been advanced in the event S&P reduces our bond rating below investment grade before we have advanced the required construction funds. However, we are relieved of these commitments (i) to the extent of 50% of any borrowing agreements that the joint venture has obtained and maintains for funding the construction of the pipeline and (ii) to the extent we or our subsidiary participating in the joint venture obtains committed borrowing agreements pursuant to which funds may be borrowed and used for the construction of the pipeline. A similar commitment has been provided by the other party to the joint venture. As of June 30, 2008, our subsidiaries have advanced approximately $457 million to SESH, of which $219 million was in the form of an equity contribution and $238 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 June 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.

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

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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 indemity 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

•

various other risks identified in “Risk Factors” in Item 1A of our 2007 Form 10-K.

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 June 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 June 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

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Item 1A. RISK FACTORS

There have been no material changes from the risk factors disclosed in our 2007 Form 10-K.

Item 5. OTHER INFORMATION

Our ratio of earnings to fixed charges for the six months ended June 30, 2007 and 2008 was 3.44 and 3.82, respectively. We do not believe that the ratios for these six-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 June 30, 2003	1-13265	3(a)(4)

3.2	– Bylaws of RERC Corp.	Form 10-K for the year ended December 31, 1997	1-13265	3(b)

4.1	– $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 June 30, 2007	1-13265	4.1

4.2	– Indenture, dated as of February 1, 1998, between Reliant Energy Resources Corp. and Chase Bank of Texas, National Association, as Trustee	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 June 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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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: August 13, 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 June 30, 2003	1-13265	3(a)(4)

3.2	– Bylaws of RERC Corp.	Form 10-K for the year ended December 31, 1997	1-13265	3(b)

4.1	– $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 June 30, 2007	1-13265	4.1

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

ex12.htm

Exhibit 12

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

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

COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES

(Millions of Dollars)

	Six Months Ended June 30,
	2007			2008

Net Income	$	161		$	186
Income taxes		95			116
Capitalized interest		(10	)		(3	)
		246			299

Fixed charges, as defined:

Interest		84			97
Capitalized interest		10			3
Interest component of rentals charged to operating income		7			6
Total fixed charges		101			106

Earnings, as defined	$	347		$	405

Ratio of earnings to fixed charges		3.44			3.82

ex31-1.htm

Exhibit 31.1

CERTIFICATIONS

I, David M. McClanahan, certify that:

1. I have reviewed this quarterly report on Form 10-Q of CenterPoint Energy Resources Corp.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)

Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)

Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 13, 2008

	/s/ David M. McClanahan
	David M. McClanahan
	President and Chief Executive Officer

ex31-2.htm

Exhibit 31.2

CERTIFICATIONS

I, Gary L. Whitlock, certify that:

1. I have reviewed this quarterly report on Form 10-Q of CenterPoint Energy Resources Corp.;

(a)

(b)

(c)

(d)

(a)

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 13, 2008

	/s/ Gary L. Whitlock
	Gary L. Whitlock
	Executive Vice President and Chief Financial Officer

ex32-1.htm

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of CenterPoint Energy Resources Corp. (the “Company”) on Form 10-Q for the quarter ended June 30, 2008 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, David M. McClanahan, Chief Executive Officer, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

1. The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ David M. McClanahan
David M. McClanahan
President and Chief Executive Officer
August 13, 2008

ex32-2.htm

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of CenterPoint Energy Resources Corp. (the “Company”) on Form 10-Q for the quarter ended June 30, 2008 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, Gary L. Whitlock, Chief Financial Officer, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

1. The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Gary L. Whitlock
Gary L. Whitlock
Executive Vice President and Chief Financial Officer
August 13, 2008

ex99-1.htm

Exhibit 99.1

Item 1A. Risk Factors

The following, along with any additional legal proceedings identified or incorporated by reference in Item 3 of this report, summarizes the principal risk factors associated with our business.

Risk Factors Affecting Our Businesses

Rate regulation of our business may delay or deny our ability to earn a reasonable return and fully recover our costs.

Rates for Gas Operations are regulated by certain municipalities and state commissions, and the rates of our interstate pipelines are regulated by the FERC, based on an analysis of our invested capital and our expenses in a test year. Thus, the rates that we are allowed to charge may not match our expenses at any given time. The regulatory process in which rates are determined may not always result in rates that will produce full recovery of our costs and enable us to earn a reasonable return on our invested capital.

Our businesses must compete with alternative energy sources, which could result in our marketing less natural gas, and our interstate pipelines and field services businesses must compete directly with others in the transportation, storage, gathering, treating and processing of natural gas, which could lead to lower prices, either of which could have an adverse impact on our results of operations, financial condition and cash flows.

We compete primarily with alternate energy sources such as electricity and other fuel sources. In some areas, intrastate pipelines, other natural gas distributors and marketers also compete directly with us for natural gas sales to end-users. In addition, as a result of federal regulatory changes affecting interstate pipelines, natural gas marketers operating on these pipelines may be able to bypass our facilities and market, sell and/or transport natural gas directly to commercial and industrial customers. Any reduction in the amount of natural gas marketed, sold or transported by us as a result of competition may have an adverse impact on our results of operations, financial condition and cash flows.

Our two interstate pipelines and our gathering systems compete with other interstate and intrastate pipelines and gathering systems in the transportation and storage of natural gas. The principal elements of competition are rates, terms of service, and flexibility and reliability of service. We also compete indirectly with other forms of energy, including electricity, coal and fuel oils. The primary competitive factor is price. The actions of our competitors could lead to lower prices, which may have an adverse impact on our results of operations, financial condition and cash flows.

Our natural gas distribution and competitive natural gas sales and services businesses are subject to fluctuations in natural gas pricing levels, which could affect the ability of our suppliers and customers to meet their obligations or otherwise adversely affect our liquidity.

We are subject to risk associated with increases in the price of natural gas. Increases in natural gas prices might affect our ability to collect balances due from our customers and, for Gas Operations, could create the potential for uncollectible accounts expense to exceed the recoverable levels built into our tariff rates. In addition, a sustained period of high natural gas prices could apply downward demand pressure on natural gas consumption in the areas in which we operate and increase the risk that our suppliers or customers fail or are unable to meet their obligations. Additionally, increasing natural gas prices could create the need for us to provide collateral in order to purchase natural gas.

If we were to fail to renegotiate a contract with one of our significant pipeline customers or if we renegotiate the contract on less favorable terms, there could be an adverse impact on our operations.

Since October 31, 2006, our contract with Laclede, one of our pipeline customers, has been terminable upon one year’s prior notice. We have not received a termination notice and are currently negotiating a long-term contract with Laclede. If Laclede were to terminate this contract or if we were to renegotiate this contract at rates

substantially lower than the rates provided in the current contract, there could be an adverse effect on our results of operations, financial condition and cash flows.

A decline in our credit rating could result in us having to provide collateral in order to purchase gas.

If our credit rating were to decline, we might be required to post cash collateral in order to purchase natural gas. If a credit rating downgrade and the resultant cash collateral requirement were to occur at a time when we were experiencing significant working capital requirements or otherwise lacked liquidity, we might be unable to obtain the necessary natural gas to meet our obligations to customers, and our results of operations, financial condition and cash flows would be adversely affected.

The revenues and results of operations of our interstate pipelines and field services businesses are subject to fluctuations in the supply of natural gas.

Our interstate pipelines and field services businesses largely rely on natural gas sourced in the various supply basins located in the Mid-continent region of the United States. To the extent the availability of this supply is substantially reduced, it could have an adverse effect on our results of operations, financial condition and cash flows.

Our revenues and results of operations are seasonal.

A substantial portion of our revenues is derived from natural gas sales and transportation. Thus, our revenues and results of operations are subject to seasonality, weather conditions and other changes in natural gas usage, with revenues being higher during the winter months.

The actual cost of pipelines under construction and related compression facilities may be significantly higher than our current estimates.

Our subsidiaries are involved in significant pipeline construction projects. The construction of new pipelines and related compression facilities requires the expenditure of significant amounts of capital, which may exceed our estimates. These projects may not be completed at the budgeted cost, on schedule or at all. The construction of new pipeline or compression facilities is subject to construction cost overruns due to labor costs, costs of equipment and materials such as steel and nickel, labor shortages or delays, weather delays, inflation or other factors, which could be material. In addition, the construction of these facilities is typically subject to the receipt of approvals and permits from various regulatory agencies. Those agencies may not approve the projects in a timely manner or may impose restrictions or conditions on the projects that could potentially prevent a project from proceeding, lengthen its expected completion schedule and/or increase its anticipated cost. As a result, there is the risk that the new facilities may not be able to achieve our expected investment return, which could adversely affect our financial condition, results of operations or cash flows.

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

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

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

Risk Factors Associated with Our Consolidated Financial Condition

If we are unable to arrange future financings on acceptable terms, our ability to refinance existing indebtedness could be limited.

As of December 31, 2007, we had $3.0 billion of outstanding long-term indebtedness on a consolidated basis. As of December 31, 2007, approximately $319 million principal amount of this debt must be paid through 2010. Our future financing activities may depend, at least in part, on:

	•		general economic and capital market conditions;

	•		credit availability from financial institutions and other lenders;

	•		investor confidence in us and the market in which we operate;

	•		maintenance of acceptable credit ratings;

	•		market expectations regarding our future earnings and probable cash flows;

	•		market perceptions of our and CenterPoint Energy’s ability to access capital markets on reasonable terms; and

	•		provisions of relevant tax and securities laws.

Our current credit ratings are discussed in “Management’s Narrative Analysis of Results of Operations — Liquidity — Impact on Liquidity of a Downgrade in Credit Ratings” in Item 7 of this report. These credit ratings may not remain in effect for any given period of time and one or more of these ratings may 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. Each rating should be evaluated independently of any other rating. Any future reduction or withdrawal of one or more of our credit ratings could have a material adverse impact on our ability to access capital on acceptable terms.

The financial condition and liquidity of our parent company could affect our access to capital, our credit standing and our financial condition.

Our ratings and credit may be impacted by CenterPoint Energy’s credit standing. As of December 31, 2007, CenterPoint Energy and its subsidiaries other than us have approximately $523 million principal amount of debt required to be paid through 2010. This amount excludes amounts related to capital leases, transition bonds and indexed debt securities obligations, but includes $123 million of 3.75% convertible notes converted by holders in January and February 2008. In addition, CenterPoint Energy has cash settlement obligations with respect to $412 million of outstanding 3.75% convertible notes on which holders could exercise their conversion rights during the first quarter of 2008 and in subsequent quarters in which CenterPoint Energy’s common stock price causes such notes to be convertible. We cannot assure you that CenterPoint Energy and its other subsidiaries will be able to pay or refinance these amounts. If CenterPoint Energy were to experience a deterioration in its credit standing or liquidity difficulties, our access to credit and our credit ratings could be adversely affected.

We are an indirect wholly owned subsidiary of CenterPoint Energy. CenterPoint Energy can exercise substantial control over our dividend policy and business and operations and could do so in a manner that is adverse to our interests.

We are managed by officers and employees of CenterPoint Energy. Our management will make determinations with respect to the following:

	•		our payment of dividends;

	•		decisions on our financings and our capital raising activities;

	•		mergers or other business combinations; and

	•		our acquisition or disposition of assets.

There are no contractual restrictions on our ability to pay dividends to CenterPoint Energy. Our management could decide to increase our dividends to CenterPoint Energy to support its cash needs. This could adversely affect our liquidity. However, under our credit facility and our receivables facility, our ability to pay dividends is restricted by a covenant that debt as a percentage of total capitalization may not exceed 65%.

The use of derivative contracts by us and our subsidiaries in the normal course of business could result in financial losses that negatively impact our results of operations and those of our subsidiaries.

We and our subsidiaries use derivative instruments, such as swaps, options, futures and forwards, to manage our commodity, weather and financial market risks. We and our subsidiaries could recognize financial losses as a result of volatility in the market values of these contracts, or should a counterparty fail to perform. In the absence of actively quoted market prices and pricing information from external sources, the valuation of these financial instruments can involve management’s judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts.

We derive a substantial portion of our operating income from subsidiaries through which we hold a substantial portion of our assets.

We derive a substantial portion of our operating income from, and hold a substantial portion of our assets through, our subsidiaries. In general, these subsidiaries are separate and distinct legal entities and have no obligation to provide us with funds for our payment obligations, whether by dividends, distributions, loans or otherwise. In addition, provisions of applicable law, such as those limiting the legal sources of dividends, limit our subsidiaries’ ability to make payments or other distributions to us, and our subsidiaries could agree to contractual restrictions on their ability to make distributions.

Our right to receive any assets of any subsidiary, and therefore the right of our creditors to participate in those assets, will be effectively subordinated to the claims of that subsidiary’s creditors, including trade creditors. In addition, even if we were a creditor of any subsidiary, our rights as a creditor would be subordinated to any security interest in the assets of that subsidiary and any indebtedness of the subsidiary senior to that held by us.

Other Risks

We are subject to operational and financial risks and liabilities arising from environmental laws and regulations.

Our operations are subject to stringent and complex laws and regulations pertaining to health, safety and the environment, as discussed in “Business — Environmental Matters” in Item 1 of this report. As an owner or operator of natural gas pipelines and distribution systems, and gas gathering and processing systems, we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as:

	•		restricting the way we can handle or dispose of wastes;

	•		limiting or prohibiting construction activities in sensitive areas such as wetlands, coastal regions, or areas inhabited by endangered species;
	•		requiring remedial action to mitigate pollution conditions caused by our operations, or attributable to former operations; and


	•		enjoining the operations of facilities deemed in non-compliance with permits issued pursuant to such environmental laws and regulations.

In order to comply with these requirements, we may need to spend substantial amounts and devote other resources from time to time to:

	•		construct or acquire new equipment;

	•		acquire permits for facility operations;

	•		modify or replace existing and proposed equipment; and

	•		clean up or decommission waste disposal areas, fuel storage and management facilities and other locations and facilities.

Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial actions, and the issuance of orders enjoining future operations. Certain environmental statutes impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other waste products into the environment.

Our insurance coverage may not be sufficient. Insufficient insurance coverage and increased insurance costs could adversely impact our results of operations, financial condition and cash flows.

We currently have general liability and property insurance in place to cover certain of our facilities in amounts that we consider appropriate. Such policies are subject to certain limits and deductibles and do not include business interruption coverage. Insurance coverage may not be available in the future at current costs or on commercially reasonable terms, and the insurance proceeds received for any loss of, or any damage to, any of our facilities may not be sufficient to restore the loss or damage without negative impact on our results of operations, financial condition and cash flows.

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

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

Prior to CenterPoint Energy’s distribution of its ownership in RRI to its shareholders, we had guaranteed certain contractual obligations of what became RRI’s trading subsidiary. Under the terms of the separation agreement between the companies, RRI agreed to extinguish all such guaranty obligations prior to separation, but at the time of separation in September 2002, RRI had been unable to extinguish all obligations. To secure us 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 February 2007, we and CenterPoint Energy made a formal demand on RRI in connection with one of the two remaining guaranties under procedures provided by the Master Separation Agreement, dated December 31, 2000, between Reliant Energy and

RRI. That demand sought to resolve a disagreement with RRI over the amount of security RRI is obligated to provide with respect to this guaranty. In December 2007, we, CenterPoint Energy and RRI amended the agreement relating to the security to be provided by RRI for these guaranties, pursuant to which we released the $29.3 million in letters of credit RRI had provided as security, and 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 remaining exposure under the guaranties relates to payment of demand charges related to transportation contracts. The present value of the demand charges under those transportation contracts, which will be effective until 2018, was approximately $135 million as of December 31, 2007. RRI continues to meet its obligations under the contracts, and we believe current market conditions make those contracts valuable in the near term and that additional security is not needed at this time. However, changes in market conditions could affect the value of those contracts. If RRI should fail to perform its obligations under the contracts or if RRI should fail to provide security in the event market conditions change adversely, our exposure to the counterparty under the guaranty could exceed the security provided by RRI.

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