Centerpoint Energy Resources 10-Q 2009 Q1 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C.  20549

FORM 10-Q

(Mark One)
R	QUARTERLY  REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2009
OR
£	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	FOR THE TRANSITION PERIOD FROM TO

Commission file number 1-13265

CENTERPOINT ENERGY RESOURCES CORP.

(Exact name of registrant as specified in its charter)

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

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes £  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 April 30, 2009, all 1,000 shares of CenterPoint Energy Resources Corp. common stock were held by Utility Holding, LLC, a wholly owned subsidiary of CenterPoint Energy, Inc.

CENTERPOINT ENERGY RESOURCES CORP.

QUARTERLY REPORT ON FORM 10-Q

FOR THE QUARTER ENDED MARCH 31, 2009

TABLE OF CONTENTS

PART I.	FINANCIAL INFORMATION
Item 1.	Financial Statements	1
	Condensed Statements of Consolidated Income
	Three Months Ended March 31, 2008 and 2009 (unaudited)	1
	Condensed Consolidated Balance Sheets
	December 31, 2008 and March 31, 2009 (unaudited)	2
	Condensed Statements of Consolidated Cash Flows
	Three Months Ended March 31, 2008 and 2009 (unaudited)	4
	Notes to Unaudited Condensed Consolidated Financial Statements	5
Item 2.	Management’s Narrative Analysis of Results of Operations	19
Item 4T.	Controls and Procedures	27
PART II.	OTHER INFORMATION
Item 1.	Legal Proceedings	27
Item 1A.	Risk Factors	27
Item 5.	Other Information	27
Item 6.	Exhibits	28

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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, including deregulation, re-regulation, 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 and natural gas liquids;

• 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., now known as RRI Energy, Inc., and its subsidiaries and any successors to satisfy their other 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;

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• the investment performance of CenterPoint Energy, Inc.’s employee benefit plans;

• our potential business strategies, including acquisitions or dispositions of assets or businesses, which we cannot assure will be completed or will have the anticipated benefits to us;

• 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, 2008, 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.

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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 March 31,
	2008			2009
Revenues	$	2,952		$	2,351
Expenses:
Natural gas		2,393			1,789
Operation and maintenance		205			233
Depreciation and amortization		54			57
Taxes other than income taxes		58			58
Total		2,710			2,137
Operating Income		242			214
Other Income (Expense): Interest and other finance charges		(48	)		(54	)
Equity in earnings of unconsolidated affiliates		9			—
Other, net		2			1
Total		(37	)		(53	)
Income Before Income Taxes		205			161
Income tax expense		(79	)		(66	)
Net Income	$	126		$	95

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, 2008		March 31, 2009
Current Assets:
Cash and cash equivalents	$	1	$	6
Accounts and notes receivable, net		774		682
Accrued unbilled revenue		480		247
Accounts and notes receivable – affiliated companies		9		9
Materials and supplies		54		64
Natural gas inventory		441		12
Non-trading derivative assets		118		119
Deferred tax asset		25		8
Prepaid expenses and other current assets		327		287
Total current assets		2,229		1,434
Property, Plant and Equipment:
Property, plant and equipment		6,313		6,437
Less accumulated depreciation and amortization		950		1,002
Property, plant and equipment, net		5,363		5,435
Other Assets:
Goodwill		1,696		1,696
Non-trading derivative assets		20		23
Investment in unconsolidated affiliates		345		343
Notes receivable from unconsolidated affiliates		323		323
Other		235		259
Total other assets		2,619		2,644
Total Assets	$	10,211	$	9,513

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, 2008			March 31, 2009
Current Liabilities:
Short-term borrowings	$	153		$	215
Current portion of long-term debt		7			7
Accounts payable		722			369
Accounts and notes payable — affiliated companies		33			32
Taxes accrued		99			102
Interest accrued		54			68
Customer deposits		59			62
Non-trading derivative liabilities		87			63
Other		302			166
Total current liabilities		1,516			1,084
Other Liabilities:
Accumulated deferred income taxes, net		864			888
Non-trading derivative liabilities		47			47
Benefit obligations		114			112
Regulatory liabilities		508			521
Other		101			117
Total other liabilities		1,634			1,685
Long-term Debt		3,712			3,300
Commitments and Contingencies (Note 11)
Stockholder’s Equity:
Common stock		—			—
Paid-in capital		2,416			2,416
Retained earnings		935			1,030
Accumulated other comprehensive loss		(2	)		(2	)
Total stockholder’s equity		3,349			3,444
Total Liabilities and Stockholder’s Equity	$	10,211		$	9,513

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)

	Three Months Ended March 31,
	2008			2009
Cash Flows from Operating Activities:
Net income	$	126		$	95
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		54			57
Amortization of deferred financing costs		2			2
Deferred income taxes		28			41
Write-down of natural gas inventory		—			6
Equity in earnings of unconsolidated affiliates, net of distributions		(9	)		—
Changes in other assets and liabilities:
Accounts receivable and unbilled revenues, net		(103	)		273
Accounts receivable/payable, affiliates		51			(1	)
Inventory		328			413
Accounts payable		46			(341	)
Fuel cost over (under) recovery		29			(30	)
Interest and taxes accrued		4			17
Non-trading derivatives, net		27			11
Margin deposits, net		29			(62	)
Other current assets		57			54
Other current liabilities		(64	)		(51	)
Other assets		4			1
Other liabilities		(55	)		—
Net cash provided by operating activities		554			485
Cash Flows from Investing Activities:
Capital expenditures		(94	)		(132	)
Increase in notes receivable from affiliates, net		(2	)		—
Investment in unconsolidated affiliates		(105	)		2
Net cash used in investing activities		(201	)		(130	)
Cash Flows from Financing Activities:
Increase (decrease) in short-term borrowings		(32	)		62
Long-term revolving credit facility, net		(50	)		(425	)
Proceeds from commercial paper, net		35			19
Payments of long-term debt		(307	)		(6	)
Increase in notes payable with affiliates		19			—
Net cash used in financing activities		(335	)		(350	)
Net Increase in Cash and Cash Equivalents		18			5
Cash and Cash Equivalents at Beginning of the Period		1			1
Cash and Cash Equivalents at End of the Period	$	19		$	6
Supplemental Disclosure of Cash Flow Information:
Cash Payments:
Interest, net of capitalized interest	$	46		$	37
Income taxes		36			19
Non-cash transactions:
Accounts payable related to capital expenditures		44			39

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, 2008 (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 requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period.  Actual results could differ from those estimates.

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

For a description of the Company’s reportable business segments, see Note 13.

(2) New Accounting Pronouncements

In December 2007, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standard (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 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’s adoption of SFAS No. 160 as of January 1, 2009 did not have a material impact on its financial position, results of operations or cash flows.

Effective January 1, 2009, the Company adopted SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities ─ an amendment of FASB Statement No. 133” (SFAS No. 161). SFAS No. 161 amends SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS No. 133) which requires

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enhanced disclosures of derivative instruments and hedging activities such as the fair value of derivative instruments and presentation of their gains or losses in tabular format, as well as disclosures regarding credit risks and strategies and objectives for using derivative instruments.  These disclosures are included as part of the Company’s Derivatives Instruments footnote (see Note 5).

In December 2008, the FASB issued FASB Staff Position No. FAS 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets” (FSP 132(R)-1), which amends SFAS No. 132(R), “Employers’ Disclosures about Pensions and Other Postretirement Benefits.”  FSP 132(R)-1 expands the disclosures about employers’ plan assets to include more detailed disclosures about the employers’ investment strategies, major categories of plan assets, concentrations of risk within plan assets and valuation techniques used to measure the fair value of plan assets. FSP 132(R)-1 is effective for fiscal years ending after December 15, 2009. The Company expects that the adoption of FSP 132(R)-1 will not have a material impact on its financial position, results of operations or cash flows.

In April 2009, the FASB issued FASB Staff Position No. FAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments” (FSP 107-1), which amends SFAS No. 107, “Disclosures about Fair Value of Financial Instruments” (SFAS No. 107) and APB 28-1, “Interim Financial Reporting.” FSP 107-1 expands the fair value disclosures required for all financial instruments within the scope of SFAS No. 107 to interim periods. FSP 107-1 also requires entities to disclose in interim periods the methods and significant assumptions used to estimate the fair value of financial instruments. FSP 107-1 is effective for interim reporting periods ending after June 15, 2009. The Company expects that the adoption of FSP 107-1 will not have a material impact on its financial position, results of operations or cash flows.

(3) Employee Benefit Plans

The Company’s employees participate in CenterPoint Energy’s postretirement benefit plan.  The Company’s net periodic cost relating to postretirement benefits includes $2 million of interest cost for each of the three months ended March 31, 2008 and 2009. The Company expects to contribute approximately $15 million to CenterPoint Energy’s postretirement benefits plan in 2009, of which $4 million had been contributed as of March 31, 2009.

(4) Regulatory Matters

Texas. In March 2008, the Company’s natural gas distribution businesses (Gas Operations) filed a request to change its rates with the Railroad Commission of Texas (Railroad Commission) and the 47 cities in its Texas Coast service territory, an area consisting of approximately 230,000 customers in cities and communities on the outskirts of Houston. The request sought to establish uniform rates, charges and terms and conditions of service for the cities and environs of the Texas Coast service territory. Of the 47 cities, 23 either affirmatively approved or allowed the filed rates to go into effect by operation of law.  Nine other cities were represented by the Texas Coast Utilities Coalition (TCUC) and 15 cities were represented by the Gulf Coast Coalition of Cities (GCCC). In July 2008, Gas Operations reached a settlement agreement with the GCCC. That settlement agreement, if implemented across the entire Texas Coast service territory, would allow Gas Operations a $3.4 million annual increase in revenues. The TCUC cities denied the rate change request and Gas Operations appealed the denial of rates to the Railroad Commission. The Railroad Commission issued an order in October 2008, which, if implemented across the entire Texas Coast service territory, would result in an annual revenue increase of $3.7 million. Both the Railroad Commission order and the settlement provide for an annual rate adjustment mechanism to reflect changes in operating expenses and revenues as well as changes in capital investment and associated changes in revenue-related taxes. In December 2008, the Railroad Commission issued an order on rehearing.  Parties filed second motions for rehearing on this order.  In December 2008, Gas Operations implemented the approved rates for the nine TCUC cities and the environs.  In February 2009, the Railroad Commission denied the second motions on rehearing reaffirming its original decision.  Cities with settled rates have the opportunity to adopt the rates established by the Railroad Commission or retain the rates agreed to in their settlements.  In March 2009, TCUC and the State of Texas appealed the Railroad Commission’s decision to the 353rd Judicial District Court, Travis County, Texas.  The Company does not expect the outcome of this litigation to have a material adverse impact on its financial condition, results of operations or cash flows.

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

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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.  In January 2009, the Minnesota Supreme Court heard oral arguments. While there is no deadline for a decision, a decision is expected by the end of the third quarter of 2009. While no prediction can be made as to the ultimate outcome, this matter will have no negative impact on the Company’s financial condition, results of operations or cash flows.

In November 2008, Gas Operations filed a request with the MPUC to increase its rates for utility distribution service.  If approved by the MPUC, the proposed new rates would result in an overall increase in annual revenue of $59.8 million.  The proposed increase would allow Gas Operations to recover increased operating costs, including higher bad debt and collection expenses, the cost of improved customer service and inflationary increases in other expenses.  It also would allow recovery of increased costs related to conservation improvement programs and provide a return for the additional capital invested to serve its customers.  In addition, Gas Operations is seeking an adjustment mechanism that would annually adjust rates to reflect changes in use per customer.  In December 2008, the MPUC accepted the case and approved an interim rate increase of $51.2 million, which became effective on January 2, 2009, subject to refund. The Company does not expect an order from the MPUC until early 2010.

(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, weather and interest rates on its operating results and cash flows. Such contracts are recognized in the Company’s Condensed Consolidated Balance Sheets at their fair value unless the Company elects the normal purchase and sales exemption for qualified physical transactions. A derivative contract may be designated as a normal purchase or sale if the intent is to physically receive or deliver the product for use or sale in the normal course of business. If derivative contracts are designated as a cash flow hedge according to SFAS No. 133, the effective portions of the changes in their fair values are reflected initially as a separate component of stockholders’ equity and subsequently recognized in income at the same time the hedged items impact earnings. The ineffective portions of changes in fair values of derivatives designated as hedges are immediately recognized in income. Changes in other derivatives not designated as normal or as a cash flow hedge are recognized in income as they occur. The Company does not enter into or hold derivative instruments for trading purposes.

CenterPoint Energy has a Risk Oversight Committee composed of corporate and business segment officers that oversees all commodity price, weather and credit risk activities, including the Company’s marketing, risk management services and hedging activities. The committee’s duties are to establish the Company’s commodity risk policies, allocate risk capital within limits established by CenterPoint Energy’s board of directors, approve use of new products and commodities, monitor positions and ensure compliance with the Company’s risk management policies and procedures and limits established by CenterPoint Energy’s board of directors.

The Company’s policies prohibit the use of leveraged financial instruments. A leveraged financial instrument, for this purpose, is a transaction involving a derivative whose financial impact will be based on an amount other than the notional amount or volume of the instrument.

(a)Non-Trading Activities

Derivative Instruments. 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 March 31, 2008, the Company

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decreased natural gas revenues from unrealized net losses of $20 million and increased natural gas expense from unrealized net losses of $2 million, resulting in a net unrealized loss of $22 million. During the three months ended March 31, 2009, the Company increased revenues from unrealized net gains of $3 million and increased natural gas expense from unrealized net losses of $22 million, resulting in a net unrealized loss of $19 million.

In prior years, the Company entered into certain derivative instruments that were designated as cash flow hedges under SFAS No. 133. The objective of these derivative instruments was 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.  In 2007, the Company discontinued designating these instruments as cash flow hedges under SFAS No. 133.  As of March 31, 2009, there are no remaining amounts deferred in other comprehensive income related to these instruments that had previously been designated as cash flow hedges.

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

In 2007, the Company entered into heating-degree day swaps to mitigate the effect of fluctuations from normal weather on its financial position and cash flows for the 2007-2008 winter heating season.  The swaps were based on ten-year normal weather. 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.  During the three months ended March 31, 2008 and 2009, the Company recognized losses of $11 million and $3 million, respectively, related to these swaps.  Such amounts were substantially offset by increased margin due to colder than normal weather. These weather derivative losses are included in revenues in the Condensed Statements of Consolidated Income.

(b) Derivative Fair Values and Income Statement Impacts

The following tables present information about the Company’s derivative instruments and hedging activities.  The first table provides a balance sheet overview of the Company’s Derivative Assets and Liabilities as of March 31, 2009, while the latter table provides a breakdown of the related income statement impact for the three months ended March 31, 2009.

Fair Value of Derivative Instruments
	March 31, 2009
Total derivatives not designated as hedging instruments under SFAS 133	Balance Sheet Location	Derivative Assets Fair Value (2) (3)		Derivative Liabilities Fair Value (2) (3)
		(in millions)
Commodity contracts (1)	Current Assets	$	133	$	(14	)
Commodity contracts(1)	Other Assets		24		(1	)
Commodity contracts (1)	Current Liabilities		12		(222	)
Commodity contracts (1)	Other Liabilities		1		(149	)
Total		$	170	$	(386	)

(1)  Commodity contracts are subject to master netting arrangements and are presented on a net basis in the Consolidated Balance Sheet. This netting causes derivative assets (liabilities) to be ultimately presented net in a liability (asset) account within the Consolidated Balance Sheet.

(2)  The fair value shown for commodity contracts is comprised of derivative volumes totaling 688 billion cubic feet (Bcf).  These volumes are disclosed in absolute terms, not net.  Basis swaps constitute 261 Bcf of the total.

(3) The net of total non-trading derivative assets and liabilities is $32 million as shown on the Company’s Condensed Consolidated Balance Sheets, and is comprised of the commodity contracts derivative assets and liabilities separately shown above offset by collateral netting of $248 million.

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For the Company’s price stabilization activities of the Natural Gas Distribution business segment, the settled costs of derivatives are ultimately recovered through purchased gas adjustments. Accordingly, the net unrealized gains and losses associated with interim price movements on contracts that are accounted for as derivatives and probable of recovery through purchased gas adjustments are recorded as net regulatory assets. For those derivatives that are not included in purchased gas adjustments, unrealized gains and losses and settled amounts are recognized on the Condensed Statements of Consolidated Income as revenue for retail sales derivative contracts and as natural gas expense for natural gas derivatives and non-retail related physical gas derivatives.

Income Statement Impact of Derivative Activity
Total derivatives not designated as hedging instruments under SFAS 133	Income Statement Location	Three Months Ended March 31, 2009
		(in millions)
Commodity contracts	Gains (Losses) in Revenue	$	77
Commodity contracts (1)	Gains (Losses) in Expense: Natural Gas		(149	)
Total		$	(72	)

(1) The Gains (Losses) in Expense: Natural Gas contains $(78) million of costs associated with price stabilization activities of our Natural Gas Distribution business segment which are ultimately recovered through purchased gas adjustments.  In addition, for the period a $(91) million unrealized loss associated with unsettled price stabilization derivatives was recorded into the net regulatory asset account.

(c) Credit Risk Contingent Features

The Company enters into financial derivative contracts containing material adverse change provisions.  These provisions require the Company to post additional collateral if the Standard & Poor’s Rating Services or Moody’s Investors Service, Inc. credit rating of the Company is downgraded.  The total fair value of the derivative instruments that contain credit risk contingent features that are in a net liability position at March 31, 2009 is $250 million.  The aggregate fair value of assets that are already posted as collateral at March 31, 2009 is $162 million.  If all derivative contracts (in a net liability position) containing credit risk contingent features were triggered at March 31, 2009, $88 million of additional assets would be required to be posted as collateral.

(6) Fair Value Measurements

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. Effective January 1, 2009, the Company adopted SFAS No. 157 for nonfinancial assets and liabilities, which adoption had no impact on the Company’s financial position, results of operations or cash flows.  Beginning in January 2008, assets and liabilities recorded at fair value in the 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. Unobservable inputs reflect the Company’s judgments

9

about the assumptions market participants would use in pricing the asset or liability since limited market data exists. The Company develops these inputs based on the best information available, including the Company’s own data.  The Company’s Level 3 derivative instruments primarily consist of options that are not traded on recognized exchanges and are valued using option pricing models.

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 March 31, 2009, and indicates the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair value.

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Netting Adjustments (1)			Balance as of March 31, 2009
	(in millions)
Assets
Investments, including money market funds	$	11	$	—	$	—	$	—		$	11
Derivative assets		1		164		7		(30	)		142
Total assets	$	12	$	164	$	7	$	(30	)	$	153
Liabilities
Derivative liabilities		41		314		33		(278	)		110
Total liabilities	$	41	$	314	$	33	$	(278	)	$	110

__________

(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 of $248 million posted 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 March 31, 2009:

	Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Derivative assets and liabilities, net
	(in millions)
Beginning liability balance as of January 1, 2009	$	(58	)
Total gains or (losses) (unrealized and realized):
Included in earnings		(3	)
Included in regulatory assets		(17	)
Purchases, sales, other settlements, net (1)		52
Ending liability balance as of March 31, 2009	$	(26	)
The amount of total 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	$	(2	)

_________

(1)  Purchases, sales, other settlements, net includes $50 million associated with price stabilization activities of the Company’s Natural Gas Distribution business segment.

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(7) Goodwill

Goodwill by reportable business segment as of both December 31, 2008 and March 31, 2009 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

(8) Comprehensive Income

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

	For the Three Months Ended March 31,
	2008			2009
	(in millions)
Net income	$	126		$	95
Other comprehensive income (loss):
Reclassification of deferred gain from cash flow hedges realized in net income (net of tax of $2)	(4		)		—
Other comprehensive loss		(4	)		—
Comprehensive income	$	122		$	95

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

	December 31, 2008			March 31, 2009
	(in millions)
Adjustment to pension and other postretirement plans	$	(2	)	$	(2	)
Total accumulated other comprehensive loss	$	(2	)	$	(2	)

(9) 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, 2008 and March 31, 2009, the Company had no borrowings from the money pool.

For the three months ended March 31, 2008 and 2009, the Company had net interest expense related to affiliate borrowings of approximately $1 million and $-0-, respectively.

CenterPoint Energy provides some corporate services to the Company. The costs of services have been charged directly to the Company using methods that management believes are reasonable. These methods include negotiated usage rates, dedicated asset assignment and proportionate corporate formulas based on operating expenses, assets, gross margin, employees and a composite of assets, gross margin and employees. 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 $35 million and $37 million for the three months ended March 31, 2008 and 2009, respectively, and are included primarily in operation and maintenance expenses.

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

(a) Short-term Borrowings

Receivables Facility. On November 25, 2008, the Company replaced a receivables facility that had terminated on October 28, 2008 with a new 364-day receivables facility. Availability under the new facility ranges from $128 million to $375 million, reflecting seasonal changes in receivables balances.  At December 31, 2008 and March 31, 2009 the facility size was $128 million and $375 million, respectively. As of December 31, 2008 and March 31, 2009, advances under the receivables facility were $78 million and $215 million, respectively.

Inventory Financing. In December 2008, the Company entered into an asset management agreement whereby it sold $110 million of its natural gas in storage and agreed to repurchase an equivalent amount of natural gas during the 2008/2009 winter heating season for payments totaling $114 million.  This transaction was accounted for as a financing and, as of December 31, 2008 and March 31, 2009, the Company’s financial statements reflect natural gas inventory of $75 million and $-0-, respectively, and a financing obligation of $75 million and $-0-, respectively, related to this transaction.

(b) Long-term Debt

Revolving Credit Facility.  The Company’s $950 million credit facility’s first drawn cost is the London Interbank Offered Rate (LIBOR) plus 45 basis points based on the Company’s current credit ratings. The facility contains a debt to total capitalization covenant.  Under the Company’s $950 million credit facility, an additional utilization fee of 5 basis points applies to borrowings any time more than 50% of the facility is utilized. The spread to LIBOR and the utilization fee fluctuate based on the Company’s credit rating.

As of December 31, 2008 and March 31, 2009, the Company had $926 million and $501 million, respectively, of borrowings under its $950 million credit facility.  There was $-0- and $19 million of commercial paper outstanding that was backstopped by the Company’s $950 million credit facility at December 31, 2008 and March 31, 2009, respectively. The Company was in compliance with all debt covenants as of March 31, 2009.

(11) 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, 2008 and March 31, 2009 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 March 31, 2009, minimum payment obligations for natural gas supply commitments are approximately $333 million for the remaining nine months in 2009, $460 million in 2010, $396 million in 2011, $393 million in 2012, $381 million in 2013 and $930 million after 2013.

(b) Legal, Environmental and Other Regulatory Matters

Legal Matters

RRI Indemnified Litigation

Gas Market Manipulation Cases. CenterPoint Energy or its predecessor, Reliant Energy, Incorporated (Reliant Energy), and certain of their present and former subsidiaries are named as defendants in several lawsuits described below. Under a master separation agreement between CenterPoint Energy and Reliant Energy, Inc., now known as RRI Energy, Inc. (RRI), CenterPoint Energy and its subsidiaries are entitled to be indemnified by RRI for any losses, including attorneys’ fees and other costs, arising out of these lawsuits.  Pursuant to the indemnification obligation, RRI is defending CenterPoint Energy and its subsidiaries to the extent named in these lawsuits.  A large number of lawsuits were filed against numerous gas market participants in a number of federal and western state courts in connection with the operation of the natural gas markets in 2000-2002. CenterPoint Energy’s former

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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, among others, recovery of compensatory damages (in some cases in excess of $1 billion), a trebling of compensatory damages, full consideration damages and attorneys’ fees. CenterPoint Energy and/or Reliant Energy were named in approximately 30 of these lawsuits, which were instituted between 2003 and 2009. Most of these cases have settled or CenterPoint Energy has been dismissed from them. CenterPoint Energy Services, Inc. (CES), a subsidiary of CERC Corp., is a defendant or sought to be added as a defendant in two cases now pending in federal court in Wisconsin and Nevada alleging a conspiracy to inflate Wisconsin natural gas prices in 2000-2002.  Additionally, CenterPoint Energy was a defendant in a lawsuit filed in state court in Nevada that was dismissed in 2007, but the plaintiffs have asked for reconsideration of the dismissal. CenterPoint Energy believes that neither it nor CES is a proper defendant in the remaining cases and will continue to pursue dismissal from those cases.  The Company does not expect the ultimate outcome of these matters to have a material impact on its financial condition, results of operations or cash flows.

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 sought review of that dismissal from the Tenth Circuit Court of Appeals, which affirmed the district court’s dismissal in March 2009. The plaintiff has indicated that he intends to seek rehearing of the Tenth Circuit decision.

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 these 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.

In October 2004, a lawsuit was filed by certain ratepayers of the Company in Texas and Arkansas in circuit court in Miller County, Arkansas against CERC Corp., CenterPoint Energy, EGMC, CenterPoint Energy Gas Transmission Company (CEGT), CenterPoint Energy Field Services (CEFS), CEPS, Mississippi River Transmission

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Corp. (MRT) and various non-affiliated companies alleging fraud, unjust enrichment and civil conspiracy with respect to rates charged to certain consumers of natural gas in Arkansas, Louisiana, Minnesota, Mississippi, Oklahoma and Texas. Subsequently, the plaintiffs dropped CEGT and MRT as defendants. Although the plaintiffs in the Miller County case sought class certification, no class was certified. In June 2007, the Arkansas Supreme Court determined that the Arkansas claims were within the sole and exclusive jurisdiction of the Arkansas Public Service Commission (APSC). In response to that ruling, in August 2007 the Miller County court stayed but refused to dismiss the Arkansas claims. In February 2008, the Arkansas Supreme Court directed the Miller County court to dismiss the entire case for lack of jurisdiction. The Miller County court subsequently dismissed the case in accordance with the Arkansas Supreme Court’s mandate and all appellate deadlines have expired.

In June 2007, CERC Corp., CenterPoint Energy, EGMC and other defendants in the Miller County case filed a petition in a district court in Travis County, Texas seeking a determination that the Railroad Commission has exclusive original jurisdiction over the Texas claims asserted in the Miller County case. In October 2007, CEFS and CEPS joined the petition in the Travis County case.  In October 2008, the district court ruled that the Railroad Commission had exclusive original jurisdiction over the Texas claims asserted against CERC Corp., CenterPoint Energy, EGMC and the other defendants in the Miller County case.  In January 2009, the court entered a final declaratory judgment ruling that the Railroad Commission has exclusive jurisdiction over Texas claims.  The Company does not anticipate that an appeal will be filed.

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. In February 2009, the Arkansas plaintiff notified the APSC that he would no longer pursue his claims. That complaint remains pending at the APSC, subject to the review of the Arkansas Attorney General, APSC Staff and the APSC.  The Company does not expect the outcome of this proceeding to have a material adverse impact on its financial condition, results of operations or cash flows.

In February 2003, a lawsuit was filed in state court in Caddo Parish, Louisiana against the Company with respect to rates charged to a purported class of certain consumers of natural gas and gas service in the State of Louisiana. In February 2004, another suit was filed in state court in Calcasieu Parish, Louisiana against the Company seeking to recover alleged overcharges for gas or gas services allegedly provided by the Company to a purported class of certain consumers of natural gas and gas service without advance approval by the Louisiana Public Service Commission (LPSC). At the time of the filing of each of the Caddo and Calcasieu Parish cases, the plaintiffs in those cases filed petitions with the LPSC relating to the same alleged rate overcharges. The Caddo and Calcasieu Parish lawsuits were stayed pending the resolution of the petitions filed with the LPSC. In August 2007, the LPSC issued an order approving a Stipulated Settlement in the review initiated by the plaintiffs in the Calcasieu Parish litigation. In the LPSC proceeding, the Company’s gas purchases were reviewed back to 1971. The review concluded that the Company’s gas costs were “reasonable and prudent,” but the Company agreed to credit to jurisdictional customers approximately $920,000, including interest, related to certain off-system sales. The refund was completed in the fourth quarter of 2008. A similar review by the LPSC related to the Caddo Parish litigation was resolved without additional payment by the Company. In October 2008, the courts considering the Caddo and Calcasieu Parish cases dismissed these cases pursuant to motions to dismiss and these proceedings have been concluded.

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

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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.

Environmental Matters

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

At March 31, 2009, 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 March 31, 2009, 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 its financial condition, results of operations or cash flows.

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

Groundwater Contamination Litigation. Predecessor entities of the Company, along with several other entities, are defendants in litigation, St. Michel Plantation, LLC, et al, v. White, et al., pending in civil district court in Orleans Parish, Louisiana.  In the lawsuit, the plaintiffs allege that their property in Terrebonne Parish, Louisiana

15

suffered salt water contamination as a result of oil and gas drilling activities conducted by the defendants.  Although a predecessor of the Company held an interest in two oil and gas leases on a portion of the property at issue, neither it nor any other entities of the Company drilled or conducted other oil and gas operations on those leases.  In January 2009, the Company and the plaintiffs reached agreement on the terms of a settlement that, if ultimately approved by the Louisiana Department of Natural Resources and the court, is expected to finally resolve this litigation.  The Company does not expect the outcome of this litigation to have a material adverse impact on its financial condition, results of operations or cash flows.

Other Environmental. From time to time the Company has received notices from regulatory authorities or others regarding its status as a PRP in connection with sites found to require remediation due to the presence of environmental contaminants. In addition, the Company has been named from time to time as a defendant in litigation related to such sites. Although the ultimate outcome of such matters cannot be predicted at this time, the Company does not expect, based on its experience to date, these matters, either individually or in the aggregate, to have a material adverse effect on the Company’s financial condition, results of operations or cash flows.

Other Proceedings

The Company is involved in other legal, environmental, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business. Some of these proceedings involve substantial amounts. The Company regularly analyzes current information and, as necessary, provides accruals for probable liabilities on the eventual disposition of these matters. The Company does not expect the disposition of these matters to have a material adverse effect on the Company’s financial condition, results of operations or cash flows.

Guaranties

Prior to CenterPoint Energy’s distribution of its ownership in 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 revised agreement if and to the extent changes in market conditions exposed the Company to a risk of loss on those guaranties.

The potential exposure to the Company under the guaranties relates to payment of demand charges related to transportation contracts. The present value of the demand charges under these transportation contracts, which will be effective until 2018, was approximately $108 million as of March 31, 2009. 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.

(12) Income Taxes

During the three months ended March 31, 2008 and 2009, the effective tax rate was 38% and 41%, respectively. The most significant item affecting the comparability of the effective tax rate is a $4 million increase in the 2009 income tax expense as a result of a state tax audit.

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The following table summarizes the Company’s liability (receivable) for 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, 2008 and March 31, 2009:

	December 31, 2008			March 31, 2009
	(in millions)
Receivable for uncertain tax positions	$	(12	)	$	(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		(4	)		(4	)

(13) Reportable Business Segments

Because the Company is an indirect wholly owned subsidiary of CenterPoint Energy, the Company’s determination of reportable business segments considers the strategic operating units under which CenterPoint Energy manages sales, allocates resources and assesses performance of various products and services to wholesale or retail customers in differing regulatory environments. The accounting policies of the business segments are the same as those described in the summary of significant accounting policies except that some executive benefit costs have not been allocated to business segments. The Company uses operating income as the measure of profit or loss for its business segments.

The Company’s reportable business segments include the following: Natural Gas Distribution, Competitive Natural Gas Sales and Services, Interstate Pipelines, Field Services and Other Operations. Natural Gas Distribution consists of intrastate natural gas sales to, and natural gas transportation and distribution for, residential, commercial, industrial and institutional customers. Competitive Natural Gas Sales and Services represents the Company’s non-rate regulated gas sales and services operations, which consist of three operational functions: wholesale, retail and intrastate pipelines. The Interstate Pipelines business segment includes the interstate natural gas pipeline operations. The Field Services business segment includes the natural gas gathering operations. Our Other Operations business segment includes unallocated corporate costs and inter-segment eliminations.

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

	For the Three Months Ended March 31, 2008
	Revenues from External Customers		Net Intersegment Revenues			Operating Income (Loss)			Total Assets as of December 31, 2008
Natural Gas Distribution	$	1,697	$	3		$	121		$	4,961
Competitive Natural Gas Sales and Services		1,109		11			6			1,315
Interstate Pipelines		91		42			71			3,578
Field Services		54		4			45			826
Other Operations		1		—			(1	)		724
Eliminations		—		(60	)		—			(1,193	)
Consolidated	$	2,952	$	—		$	242		$	10,211

	For the Three Months Ended March 31, 2009
	Revenues from External Customers		Net Intersegment Revenues			Operating Income (Loss)			Total Assets as of March 31, 2009
Natural Gas Distribution	$	1,418	$	3		$	118		$	4,344
Competitive Natural Gas Sales and Services		760		5			2			1,169
Interstate Pipelines		117		36			69			3,579
Field Services		56		1			26			829
Other Operations		—		—			(1	)		615
Eliminations		—		(45	)		—			(1,023	)
Consolidated	$	2,351	$	—		$	214		$	9,513

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(14) Subsequent Events

On May 1, 2009, RRI completed the previously announced sale of its Texas retail business to NRG Retail LLC, a subsidiary of NRG Energy, Inc.

In connection with the sale, RRI changed its name to RRI Energy, Inc. The sale does not alter RRI’s contractual obligations to indemnify CenterPoint Energy and its subsidiaries, including the Company, for certain liabilities, including their indemnification regarding certain litigation, nor does it affect the terms of existing guaranty arrangements for certain RRI gas transportation contracts.

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

The following narrative analysis should be read in combination with our Interim Condensed Financial Statements contained in Item 1 of this report and our Annual Report on Form 10-K for the year ended December 31, 2008 (2008 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 months ended March 31, 2008 and the three months ended March 31, 2009.  Reference is made to “Management’s Narrative Analysis of Results of Operations” in Item 7 of our 2008 Form 10-K.

CONSOLIDATED RESULTS OF OPERATIONS

Our results of operations are affected by seasonal fluctuations in the demand for natural gas and price movements of energy commodities as well as natural gas basis differentials.  Our results of operations are also affected by, among other things, the actions of various federal, state and local governmental authorities having jurisdiction over rates we charge, competition in our various business operations, 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 2008 Form 10-K.

The following table sets forth our consolidated results of operations for the three months ended March 31, 2008 and 2009, followed by a discussion of our consolidated results of operations.

	Three Months Ended March 31,
	2008			2009
	(in millions)
Revenues	$	2,952		$	2,351
Expenses:
Natural gas		2,393			1,789
Operation and maintenance		205			233
Depreciation and amortization		54			57
Taxes other than income taxes		58			58
Total expenses		2,710			2,137
Operating Income		242			214
Interest and other finance charges		(48	)		(54	)
Equity in earnings of unconsolidated affiliates		9			—
Other income, net		2			1
Income Before Income Taxes		205			161
Income tax expense		(79	)		(66	)
Net Income	$	126		$	95

Three months ended March 31, 2009 compared to three months ended March 31, 2008

We reported net income of $95 million for the three months ended March 31, 2009 as compared to $126 million for the same period in 2008.  The decrease in net income of $31 million was primarily due to a $28 million decrease in operating income from our business segments as discussed below, a $9 million decrease in equity in earnings of unconsolidated affiliates and a $6 million increase in interest and other finance charges, partially offset by a $13 million decrease in income tax expense.

Income Tax Expense.During the three months ended March 31, 2008 and 2009, the effective tax rate was 38% and 41%, respectively. The most significant item affecting the comparability of the effective tax rate is a $4 million increase in the 2009 income tax expense as a result of a state tax audit.

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RESULTS OF OPERATIONS BY BUSINESS SEGMENT

The following table presents operating income (loss) for each of our business segments for the three months ended March 31, 2008 and 2009, followed by a discussion of the results of operations by business segment based on operating income.  Included in revenues are intersegment sales. We account for intersegment sales as if the sales were to third parties, that is, at current market prices.

	Three Months Ended March 31,
	2008			2009
	(in millions)
Natural Gas Distribution	$	121		$	118
Competitive Natural Gas Sales and Services		6			2
Interstate Pipelines		71			69
Field Services		45			26
Other Operations		(1	)		(1	)
Total Consolidated Operating Income	$	242		$	214

Natural Gas Distribution

For information regarding factors that may affect the future results of operations of our Natural Gas Distribution business segment, please read “Risk Factors — Risk Factors Affecting Our Natural Gas Distribution, Competitive Natural Gas Sales and Services, Interstate Pipelines and Field Services Businesses,” “ — Risk Factors Associated with Our Consolidated Financial Condition” and “— Risks Common to Our Business and Other Risks” in Item 1A of Part I of our 2008 Form 10-K.

The following table provides summary data of our Natural Gas Distribution business segment for the three months ended March 31, 2008 and 2009 (in millions, except throughput and customer data):

	Three Months Ended March 31,
	2008		2009
Revenues	$	1,700	$	1,421
Expenses:
Natural gas		1,333		1,045
Operation and maintenance		156		169
Depreciation and amortization		39		40
Taxes other than income taxes		51		49
Total expenses		1,579		1,303
Operating Income	$	121	$	118
Throughput (in billion cubic feet (Bcf)):
Residential		84		78
Commercial and industrial		83		73
Total Throughput		167		151
Number of customers at period end:
Residential		2,974,411		2,996,455
Commercial and industrial		251,612		246,405
Total		3,226,023		3,242,860

Three months ended March 31, 2009 compared to three months ended March 31, 2008

Our Natural Gas Distribution business segment reported operating income of $118 million for the three months ended March 31, 2009 compared to operating income of $121 million for the three months ended March 31, 2008.  Operating margin (revenues less cost of gas) increased $9 million primarily due to increased rates ($10 million), recovery of energy-efficiency costs ($3 million) and higher miscellaneous revenue ($3 million), partially offset by reduced customer usage ($6 million) and decreased gross receipts taxes ($3 million). Margin increases from residential customer growth ($1 million), with the addition of approximately 22,000 residential customers, were

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offset by reduced margin caused by the loss of commercial customers.  Revenues related to both energy-efficiency costs and gross receipts taxes were offset by the related expenses.  Operation and maintenance expenses increased $13 million primarily due to increased pension expense ($9 million), the energy-efficiency costs above and higher bad debt expense ($2 million).

Competitive Natural Gas Sales and Services

For information regarding factors that may affect the future results of operations of our Competitive Natural Gas Sales and Services business segment, please read “Risk Factors — Risk Factors Affecting Our Natural Gas Distribution, Competitive Natural Gas Sales and Services, Interstate Pipelines and Field Services Business,” “ — Risk Factors Associated with Our Consolidated Financial Condition” and “— Risks Common to Our Business and Other Risks” in Item 1A of Part I of our 2008 Form 10-K.

The following table provides summary data of our Competitive Natural Gas Sales and Services business segment for the three months ended March 31, 2008 and 2009 (in millions, except throughput and customer data):

	Three Months Ended March 31,
	2008		2009
Revenues	$	1,120	$	765
Expenses:
Natural gas		1,105		752
Operation and maintenance		8		10
Depreciation and amortization		1		1
Taxes other than income taxes		—		—
Total expenses		1,114		763
Operating Income	$	6	$	2
Throughput (in Bcf):		138		141
Number of customers at period end		8,751		10,862

Three months ended March 31, 2009 compared to three months ended March 31, 2008

Our Competitive Natural Gas Sales and Services business segment reported operating income of $2 million for the three months ended March 31, 2009 compared to $6 million for the three months ended March 31, 2008. The decrease in operating income of $4 million was primarily due to a $6 million write down of gas in the first quarter of 2009 to the lower of cost or market as compared to no write down in the first quarter of 2008. 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 impact of mark-to-market accounting for non-trading financial derivatives for the first quarter of 2009 of $19 million versus $22 million for the same period in 2008 accounted for a $3 million increase in operating income.

Interstate Pipelines

For information regarding factors that may affect the future results of operations of our Interstate Pipelines business segment, please read “Risk Factors — Risk Factors Affecting Our Natural Gas Distribution, Competitive Natural Gas Sales and Services, Interstate Pipelines and Field Services Businesses,” “ — Risk Factors Associated with Our Consolidated Financial Condition” and “— Risks Common to Our Business and Other Risks” in Item 1A of Part I of our 2008 Form 10-K.

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The following table provides summary data of our Interstate Pipelines business segment for the three months ended March 31, 2008 and 2009 (in millions, except throughput data):

	Three Months Ended March 31,
	2008		2009
Revenues	$	133	$	153
Expenses:
Natural gas		15		29
Operation and maintenance		30		35
Depreciation and amortization		12		12
Taxes other than income taxes		5		8
Total expenses		62		84
Operating Income	$	71	$	69
Transportation throughput (in Bcf)		424		467

Three months ended March 31, 2009 compared to three months ended March 31, 2008

The Interstate Pipeline business segment reported operating income of $69 million for the three months ended March 31, 2009 compared to $71 million for the same period of 2008.  The decrease in operating income of $2 million was primarily driven by higher operation and maintenance expenses ($5 million) primarily related to costs associated with incremental facilities and increased pension expense, and higher taxes other than income ($3 million), $1 million of which was due to 2008 tax refunds.  These increases are partially offset by increased margins (revenues less natural gas costs) on Phase III of the Carthage to Perryville pipeline that went into service in April 2008 ($6 million).

Equity Earnings.  In addition, this business segment recorded equity income (loss) of $5 million and $(2) million for the three months ended March 31, 2008 and 2009, respectively, from its 50 percent interest in the Southeast Supply Header (SESH), a jointly-owned pipeline that went into service in September 2008.  The $5 million income in the first quarter of 2008 was pre-operating allowance for funds used during construction in 2008.  The $2 million loss in the first quarter of 2009 resulted from a non-cash charge of $5 million to reflect SESH’s decision to discontinue the use of Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation.”  The loss more than offset the equity income from SESH of $3 million for the first quarter of 2009.  These amounts are included in Equity in Earnings of Unconsolidated Affiliates under the Other Income (Expense) caption.

Field Services

For information regarding factors that may affect the future results of operations of our Field Services business segment, please read “Risk Factors — Risk Factors Affecting Our Natural Gas Distribution, Competitive Natural Gas Sales and Services, Interstate Pipelines and Field Services Businesses,” “ — Risk Factors Associated with Our Consolidated Financial Condition” and “— Risks Common to Our Business and Other Risks” in Item 1A of Part I of our 2008 Form 10-K.

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The following table provides summary data of our Field Services business segment for the three months ended March 31, 2008 and 2009 (in millions, except throughput data):

	Three Months Ended March 31,
	2008			2009
Revenues	$	58		$	57
Expenses:
Natural gas		(2	)		7
Operation and maintenance		11			19
Depreciation and amortization		3			4
Taxes other than income taxes		1			1
Total expenses		13			31
Operating Income	$	45		$	26
Gathering throughput (in Bcf)		98			104

Three months ended March 31, 2009 compared to three months ended March 31, 2008

The Field Services business segment reported operating income of $26 million for the three months ended March 31, 2009 compared to $45 million for the same period of 2008. The decrease in operating income of $19 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.  The remaining decrease is due to a decrease in commodity pricing offsetting the increase in margin relating to new projects.

Equity Earnings.  In addition, this business segment recorded equity income of $4 million and $2 million in the three months ended March 31, 2008 and 2009, respectively, from its 50 percent interest in a jointly-owned gas processing plant.  The decrease is driven by a decrease in liquids pricing.  These amounts are included in Equity in Earnings of Unconsolidated Affiliates 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 2008 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, tax payments and working capital needs. Our principal anticipated cash requirements for the remaining nine months of 2009 include approximately $520 million of capital expenditures.

We expect that borrowings under our credit facility, anticipated cash flows from operations and borrowings from affiliates will be sufficient to meet our anticipated cash needs in 2009. Cash needs or discretionary financing or refinancing may result in the issuance of debt securities in the capital markets or the arrangement of additional credit facilities.  Issuances of debt in the capital markets and additional credit facilities may not, however, be available to us on acceptable terms.

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

Prior to CenterPoint Energy’s distribution of its ownership in Reliant Energy, Inc., now known as RRI 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

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cash or new letters of credit to secure us against exposure under the remaining guaranties as calculated under the revised 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. The present value of the demand charges under these transportation contracts, which will be effective until 2018, was approximately $108 million as of March 31, 2009. RRI continues to meet its obligations under the contracts, and, on the basis of current market conditions, we and CenterPoint Energy believe that additional security is not needed at this time. However, if RRI should fail to perform its obligations under the contracts or if RRI should fail to provide adequate security in the event market conditions change adversely, we would retain exposure to the counterparty under the guaranty.

Credit and Receivables Facilities.  As of April 30, 2009, we had the following facilities (in millions):

Date Executed	Type of Facility	Size of Facility			Amount Utilized at April 30, 2009		Termination Date
June 29, 2007	Revolver	$	950	(1)	$	400	June 29, 2012
November 25, 2008	Receivables		375			185	November 24, 2009

________

(1) Lehman Brothers Bank, FSB, stopped funding its commitments following the bankruptcy filing of its parent in September 2008, effectively causing a reduction to the total available capacity of $20 million under CERC Corp.’s 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 $915 million commercial paper program under which we began issuing commercial paper in February 2008. As of April 30, 2009, there was $12 million of commercial paper outstanding.  As of April 30, 2009, our commercial paper is rated “P-3” by Moody’s Investors Service, Inc. (Moody’s), “A-3” by Standard & Poor’s Rating Services (S&P), 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.

Availability under our 364-day receivables facility ranges from $128 million to $375 million, reflecting seasonal changes in receivables balances.  At December 31, 2008 and March 31, 2009 the facility size was $128 million and $375 million, respectively. As of December 31, 2008 and March 31, 2009, advances under the receivables facility were $78 million and $215 million, respectively.

Securities Registered with the SEC.  As of April 30, 2009, we had a shelf registration statement covering $500 million principal amount of senior debt securities.

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Temporary Investments.  As of April 30, 2009, 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 by CenterPoint Energy under its revolving credit facility or the sale by CenterPoint Energy of its commercial paper. At April 30, 2009, 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 April 30, 2009, 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	Negative	BBB	Stable

__________

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

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

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

On April 30, 2009, S&P issued a report on CenterPoint Energy, CenterPoint Energy Houston Electric, LLC and us.  In its report, S&P affirmed the senior long-term debt ratings of the three companies but revised its outlook to negative from stable.  S&P also lowered short-term corporate credit and commercial paper program ratings for both CenterPoint Energy and us to “A-3” from “A-2”.

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 our cash collateral requirements and reduce our earnings.

CenterPoint Energy Services, Inc. (CES), our 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 March 31, 2009, the amount posted as collateral aggregated approximately $292 million. Should our credit ratings (as the credit support provider for CES) fall below certain levels, CES would be required to provide additional collateral on one business days’ notice up to the amount of its previously unsecured credit limit. We estimate that as of March 31, 2009, unsecured credit limits extended to CES by counterparties aggregate $260 million; however, utilized credit capacity was $83 million. In addition, we and our subsidiaries purchase natural gas under supply agreements that contain an aggregate credit threshold of $100 million based on our S&P senior unsecured long-term debt rating of BBB. Upgrades and downgrades from this BBB rating will increase and decrease the aggregate credit threshold accordingly.

Pipeline tariffs and contracts typically provide that if the credit ratings of a shipper or the shipper’s guarantor drop below a threshold level, which is generally investment grade ratings from both Moody’s and S&P, cash or other collateral may be demanded from the shipper in an amount equal to the sum of three months’ charges for pipeline services plus the unrecouped cost of any lateral built for such shipper. If our credit ratings decline below the applicable threshold levels, we might need to provide cash or other collateral of as much as $158 million as of March 31, 2009, the amount depending on seasonal variations in transportation levels.

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Cross Defaults. Under CenterPoint Energy’s revolving credit facility, a payment default on, or a non-payment default that permits acceleration of, any indebtedness exceeding $50 million by us will cause a default. In addition, four outstanding series of CenterPoint Energy’s senior notes, aggregating $950 million in principal amount as of April 30, 2009, 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 debt instruments or bank credit facilities.

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

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 and weather hedging and gas storage activities of our Natural Gas Distribution and Competitive Natural Gas Sales and Services business segments, particularly given gas price levels and volatility;

• acceleration of payment dates on certain gas supply contracts under certain circumstances, as a result of increased gas prices and concentration of natural gas suppliers;

• increased costs related to the acquisition of natural gas;

• increases in interest expense in connection with debt refinancings and borrowings under credit facilities;

• various regulatory actions;

• the ability of our customers to fulfill their payment obligations to us;

• the ability of RRI and its subsidiaries and any successors to satisfy their obligations to us, including indemity obligations, or in connection with the contractual obligations to a third party pursuant to which we are their 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;

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

• various other risks identified in “Risk Factors” in Item 1A of our 2008 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.

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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 March 31, 2009 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 March 31, 2009 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

PART II.  OTHER INFORMATION

Item 1.     LEGAL PROCEEDINGS

For a discussion of material legal and regulatory proceedings affecting us, please read Notes 4 and 11 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 2008 Form 10-K.

Item 1A.  RISK FACTORS

There have been no material changes from the risk factors disclosed in our 2008 Form 10-K.

Item 5.     OTHER INFORMATION

Our ratio of earnings to fixed charges for the three months ended March 31, 2008 and 2009 was 4.84 and 3.64, respectively.  We do not believe that the ratios for these three-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.

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Item 6.     Exhibits

The following exhibits are filed herewith:

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

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

Exhibit Number	Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference
3.1.1	–Certificate of Incorporation of RERC Corp.	Form 10-K for the year ended December 31, 1997	1-13265	3(a)(1)
3.1.2	–Certificate of Merger merging former NorAm Energy Corp. with and into HI Merger, Inc. dated August 6, 1997	Form 10-K for the year ended December 31, 1997	1-13265	3(a)(2)
3.1.3	–Certificate of Amendment changing the name to Reliant Energy Resources Corp.	Form 10-K for the year ended December 31, 1998	1-13265	3(a)(3)
3.1.4	–Certificate of Amendment changing the name to CenterPoint Energy Resources Corp.	Form 10-Q for the quarter ended June 30, 2003	1-13265	3(a)(4)
3.2	–Bylaws of RERC Corp.	Form 10-K for the year ended December 31, 1997	1-13265	3(b)
4.1	–$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
+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:  May 12, 2009

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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.

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

Exhibit Number	Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference
3.1.1	–Certificate of Incorporation of RERC Corp	Form 10-K for the year ended December 31, 1997	1-13265	3(a)(1)
3.1.2	–Certificate of Merger merging former NorAm Energy Corp. with and into HI Merger, Inc. dated August 6, 1997	Form 10-K for the year ended December 31, 1997	1-13265	3(a)(2)
3.1.3	–Certificate of Amendment changing the name to Reliant Energy Resources Corp.	Form 10-K for the year ended December 31, 1998	1-13265	3(a)(3)
3.1.4	–Certificate of Amendment changing the name to CenterPoint Energy Resources Corp.	Form 10-Q for the quarter ended June 30, 2003	1-13265	3(a)(4)
3.2	–Bylaws of RERC Corp.	Form 10-K for the year ended December 31, 1997	1-13265	3(b)
4.1	–$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
+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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