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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, 2010
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 27, 2010, 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, 2010

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PART I.	FINANCIAL INFORMATION

Item 1.	Financial Statements	1

	Condensed Statements of Consolidated Income
	Three Months Ended March 31, 2009 and 2010 (unaudited)	1

	Condensed Consolidated Balance Sheets
	December 31, 2009 and March 31, 2010 (unaudited)	2

	Condensed Statements of Consolidated Cash Flows
	Three Months Ended March 31, 2009 and 2010 (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	28

PART II.	OTHER INFORMATION

Item 1.	Legal Proceedings	28

Item 1A.	Risk Factors	28

Item 5.	Other Information	28

Item 6.	Exhibits	29

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

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

•

other state and federal legislative and regulatory actions or developments, including, among others, deregulation, re-regulation and health care reform;

•

timely and appropriate rate actions and increases, allowing recovery of costs and a reasonable return on investment;

•

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

•

industrial, commercial and residential growth in our service territory and changes in market demand, including the effects of energy efficiency measures, 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, including supplies available for gathering by our field services business and transporting by our interstate pipelines;

•

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 RRI Energy, Inc. (RRI) (formerly known as Reliant Energy, Inc. and Reliant Resources, Inc.) and its subsidiaries to satisfy their obligations to us, including indemnity obligations, or in connection with the contractual arrangements pursuant to which we are their guarantor;

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•

the outcome of litigation brought by or against us;

•

our ability to control costs;

•

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

•

our potential business strategies, including restructurings, 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, 2009, which is incorporated herein by reference, and other reports we file from time to time with the Securities and Exchange Commission.

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

iii

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PART I. FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

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

CONDENSED STATEMENTS OF CONSOLIDATED INCOME

(Millions of Dollars)

(Unaudited)

	Three Months Ended March 31,
	2009			2010

Revenues	$	2,351		$	2,538

Expenses:
Natural gas		1,789			1,935
Operation and maintenance		233			232
Depreciation and amortization		57			60
Taxes other than income taxes		58			63
Total		2,137			2,290

Operating Income		214			248

Other Income (Expense): Interest and other finance charges		(54	)		(51	)
Equity in earnings of unconsolidated affiliates		—			5
Other, net		1			—
Total		(53	)		(46	)

Income Before Income Taxes		161			202

Income tax expense		(66	)		(96	)

Net Income	$	95		$	106

See Notes to the 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, 2009		March 31, 2010
Current Assets:
Cash and cash equivalents	$	1	$	1
Accounts and notes receivable, net		593		704
Accrued unbilled revenue		421		242
Accounts and notes receivable – affiliated companies		13		20
Materials and supplies		69		65
Natural gas inventory		189		32
Non-trading derivative assets		39		60
Taxes receivable		47		—
Deferred tax asset		16		77
Prepaid expenses and other current assets		144		207
Total current assets		1,532		1,408

Property, Plant and Equipment:
Property, plant and equipment		6,987		7,150
Less accumulated depreciation and amortization		1,112		1,166
Property, plant and equipment, net		5,875		5,984

Other Assets:
Goodwill		1,696		1,696
Non-trading derivative assets		15		18
Investment in unconsolidated affiliates		463		478
Other		203		195
Total other assets		2,377		2,387

Total Assets	$	9,784	$	9,779

See Notes to the 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, 2009			March 31, 2010
Current Liabilities:
Short-term borrowings	$	55		$	2
Current portion of long-term debt		44			550
Accounts payable		563			448
Accounts and notes payable — affiliated companies		472			324
Taxes accrued		67			189
Interest accrued		52			67
Customer deposits		70			73
Non-trading derivative liabilities		51			53
Other		282			341
Total current liabilities		1,656			2,047

Other Liabilities:
Accumulated deferred income taxes, net		1,080			1,124
Non-trading derivative liabilities		42			32
Benefit obligations		113			111
Regulatory liabilities		539			554
Other		135			136
Total other liabilities		1,909			1,957

Long-term Debt		2,742			2,192

Commitments and Contingencies (Note 11)

Stockholder’s Equity:
Common stock		—			—
Paid-in capital		2,416			2,416
Retained earnings		1,065			1,171
Accumulated other comprehensive loss		(4	)		(4	)
Total stockholder’s equity		3,477			3,583

Total Liabilities and Stockholder’s Equity	$	9,784		$	9,779

See Notes to the 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,
	2009			2010
Cash Flows from Operating Activities:
Net income	$	95		$	106
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		57			60
Amortization of deferred financing costs		2			2
Deferred income taxes		41			(20	)
Write-down of natural gas inventory		6			—
Equity in earnings of unconsolidated affiliates, net of distributions		—			5
Changes in other assets and liabilities:
Accounts receivable and unbilled revenues, net		273			3
Accounts receivable/payable, affiliates		(1	)		(15	)
Inventory		413			161
Taxes receivable		—			47
Accounts payable		(341	)		(114	)
Fuel cost over (under) recovery		(30	)		126
Interest and taxes accrued		17			137
Non-trading derivatives, net		11			(5	)
Margin deposits, net		(62	)		(65	)
Other current assets		54			(16	)
Other current liabilities		(51	)		(6	)
Other assets		1			(2	)
Other liabilities		—			12
Other, net		—			1
Net cash provided by operating activities		485			417

Cash Flows from Investing Activities:
Capital expenditures		(132	)		(159	)
Investment in unconsolidated affiliates		2			(20	)
Net cash used in investing activities		(130	)		(179	)

Cash Flows from Financing Activities:
Increase (decrease) in short-term borrowings		62			(53	)
Revolving credit facility, net		(425	)		—
Proceeds from commercial paper, net		19			—
Payments of long-term debt		(6	)		(45	)
Decrease in notes payable with affiliates		—			(140	)
Net cash used in financing activities		(350	)		(238	)

Net Increase in Cash and Cash Equivalents		5			—
Cash and Cash Equivalents at Beginning of the Period		1			1
Cash and Cash Equivalents at End of the Period	$	6		$	1

Supplemental Disclosure of Cash Flow Information:
Cash Payments:
Interest, net of capitalized interest	$	37		$	38
Income taxes (refunds), net		19			(50	)
Non-cash transactions:
Accounts payable related to capital expenditures		39			52

See Notes to the 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). 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, 2009 (CERC Corp. Form 10-K).

Background. CERC owns and operates natural gas distribution systems in six states. Subsidiaries of CERC Corp. own interstate natural gas pipelines and gas gathering systems and provide various ancillary services. A wholly owned subsidiary of CERC Corp. offers variable and fixed-price physical natural gas supplies primarily to commercial and industrial customers and electric and gas utilities.

CERC 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.

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

For a description of CERC's reportable business segments, see Note 14.

(2)	New Accounting Pronouncements

In June 2009, the Financial Accounting Standards Board (FASB) issued new accounting guidance on consolidation of variable interest entities (VIEs) that changes how a reporting entity determines a primary beneficiary that would consolidate the VIE from a quantitative risk and rewards approach to a qualitative approach based on which variable interest holder has the power to direct the economic performance related activities of the VIE as well as the obligation to absorb losses or right to receive benefits that could potentially be significant to the VIE. This new guidance requires the primary beneficiary assessment to be performed on an ongoing basis and also requires enhanced disclosures that will provide more transparency about a company’s involvement in a VIE. This new guidance is effective for a reporting entity’s first annual reporting period that begins after November 15, 2009. CERC’s adoption of this new guidance did not have a material impact on its financial position, results of operations or cash flows.

In January 2010, the FASB issued new accounting guidance to require additional fair value related disclosures including transfers into and out of Levels 1 and 2 and separate disclosures about purchases, sales, issuances, and settlements relating to Level 3 measurements. It also clarifies existing fair value disclosure guidance about the level of disaggregation and about inputs and valuation techniques. This new guidance is effective for the first reporting period beginning after December 15, 2009 except for the requirement to separately disclose purchases, sales, issuances and settlements relating to Level 3 measurements, which is effective for the first reporting period beginning after December 15, 2010. CERC's adoption of this new guidance did not have a material impact on its financial position, results of operations or cash flows. CERC expects that the adoption of the Level 3 related gross disclosure requirement, which is effective in 2011, will not have a material impact on its financial position, results of operations or cash flows.

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

(3)	Employee Benefit Plans

CERC’s employees participate in CenterPoint Energy’s postretirement benefit plan. CERC’s net periodic cost relating to postretirement benefits includes $2 million of interest cost for each of the three months ended March 31, 2009 and 2010.

CERC expects to contribute approximately $14 million to CenterPoint Energy’s postretirement benefit plan in 2010, of which $4 million was contributed during the three months ended March 31, 2010.

(4)	Regulatory Matters

Texas. In March 2008, the natural gas distribution business of CERC (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. In 2008, the Railroad Commission approved the implementation of rates increasing annual revenues by approximately $3.5 million. The implemented rates were contested by nine cities in an appeal to the 353rd District Court in Travis County, Texas. In January 2010, that court reversed the Railroad Commission’s order in part and remanded the matter to the Railroad Commission. In its final judgment the court ruled that th e Railroad Commission lacked authority to impose the approved cost of service adjustment mechanism in both those nine cities and in those areas in which the Railroad Commission has original jurisdiction. The Railroad Commission and Gas Operations have appealed the court’s ruling on the cost of service adjustment mechanism to the court of appeals, but CenterPoint Energy and CERC do not expect the outcome of this matter to have a material adverse impact on the financial condition, results of operations or cash flows of either CenterPoint Energy or CERC.

In July 2009, Gas Operations filed a request to change its rates with the Railroad Commission and the 29 cities in its Houston service territory, consisting of approximately 940,000 customers in and around Houston. The request sought to establish uniform rates, charges and terms and conditions of service for the cities and environs of the Houston service territory. As finally submitted to the Railroad Commission and the cities, the proposed new rates would have resulted in an overall increase in annual revenue of $20.4 million, excluding carrying costs on gas inventory of approximately $2 million. In January 2010, Gas Operations withdrew its request for an annual cost of service adjustment mechanism due to the uncertainty caused by the court’s ruling in the above-mentioned Texas Coast appeal. In February 2010, the Rail road Commission issued its decision authorizing a revenue increase of $5.1 million annually, reflecting reduced depreciation rates as well as adjustments to pension and benefits, accumulated deferred income taxes and other items. The Railroad Commission also approved a surcharge of $0.9 million per year to recover Hurricane Ike costs over three years. Gas Operations and other parties filed motions for rehearing, which, except for minor corrections to the order, were denied by the Railroad Commission in May 2010. The parties are entitled to petition for judicial review by a district court in Travis County, Texas, within thirty days of the Railroad Commission’s order on rehearing.

Minnesota. In November 2008, Gas Operations filed a request with the Minnesota Public Utilities Commission (MPUC) to increase its rates for utility distribution service by $59.8 million annually. In addition, Gas Operations sought 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. In January 2010, the MPUC issued its decision authorizing a revenue increase of $41 million per year, with an overall rate of return of 8.09% (10.24% return on equity). The MPUC also authorized Gas Operations to implement a pilot program for residential and sm all volume commercial customers that is intended to decouple gas revenues from customers’ natural gas usage. In February 2010, CERC filed a request for rehearing of the order by the MPUC. No other party to the case filed such a request. In March 2010, the MPUC declined to act on CERC’s request for rehearing and a final order was issued. The difference between the amounts approved by the MPUC and amounts collected, $15 million as of March 31, 2010, is recorded in other current liabilities and will be refunded to customers when final tariffs are approved this summer.

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(5)	Derivative Instruments

CERC is exposed to various market risks. These risks arise from transactions entered into in the normal course of business. CenterPoint Energy utilizes derivative instruments such as physical forward contracts, swaps and options to mitigate the impact of changes in commodity prices and weather on its operating results and cash flows. Such derivatives are recognized in CERC’s Condensed Consolidated Balance Sheets at their fair value unless CERC elects the normal purchase and sales exemption for qualified physical transactions. A derivative may be designated as a normal purchase or sale if the intent is to physically receive or deliver the product for use or sale in the normal course of business.

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

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

(a) Non-Trading Activities

Derivative Instruments. CERC enters into certain derivative instruments to manage physical commodity price risks but does not engage in proprietary or speculative commodity trading. CERC has not elected to designate these instruments as cash flow or fair value hedges.

During the three months ended March 31, 2009, CERC recorded increased natural gas 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. During the three months ended March 31, 2010, CERC recorded increased natural gas revenues from unrealized net gains of $30 million and increased natural gas expense from unrealized net losses of $27 million, resulting in a net unrealized gain of $3 million.

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

In 2008 and 2009, CERC entered into heating-degree day swaps to mitigate the effect of fluctuations from normal weather on its financial position and cash flows for the respective winter heating seasons. The swaps were based on ten-year normal weather. During the three months ended March 31, 2009 and 2010, CERC recognized losses of $3 million and $1 million, respectively, related to these swaps. The losses were substantially offset by increased revenues due to colder than normal weather. Weather hedge losses are included in revenues in the Condensed Statements of Consolidated Income.

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(b) Derivative Fair Values and Income Statement Impacts

The following tables present information about CERC’s derivative instruments and hedging activities. The first tables provide a balance sheet overview of CERC’s Derivative Assets and Liabilities as of December 31, 2009 and March 31, 2010, while the latter tables provide a breakdown of the related income statement impact for the three months ended March 31, 2009 and March 31, 2010.

Fair Value of Derivative Instruments
	December 31, 2009
Total derivatives not designated as hedging instruments	Balance Sheet Location	Derivative Assets Fair Value (2) (3)		Derivative Liabilities Fair Value (2) (3)
		(in millions)
Natural gas contracts (1)	Current Assets	$	46	$	(7	)
Natural gas contracts (1)	Other Assets		16		(1	)
Natural gas contracts (1)	Current Liabilities		20		(123	)
Natural gas contracts (1)	Other Liabilities		1		(86	)
Total		$	83	$	(217	)

_________

(1)

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

(2)

The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling 674 billion cubic feet (Bcf) or a net 152 Bcf long position. Of the net long position, basis swaps constitute 71 Bcf and volumes associated with price stabilization activities of the Natural Gas Distribution business segment comprise 51 Bcf.

(3)

The net of total non-trading derivative assets and liabilities is a $39 million liability as shown on CERC’s Condensed Consolidated Balance Sheets, and is comprised of the natural gas contracts derivative assets and liabilities separately shown above offset by collateral netting of $95 million.

Fair Value of Derivative Instruments
	March 31, 2010
Total derivatives not designated as hedging instruments	Balance Sheet Location	Derivative Assets Fair Value (2) (3)		Derivative Liabilities Fair Value (2) (3)
		(in millions)
Natural gas contracts (1)	Current Assets	$	61	$	(1	)
Natural gas contracts (1)	Other Assets		18		—
Natural gas contracts (1)	Current Liabilities		20		(179	)
Natural gas contracts (1)	Other Liabilities		1		(81	)
Total		$	100	$	(261	)

_________

(1)

(2)

The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling 717 billion cubic feet (Bcf) or a net 181 Bcf long position. Of the net long position, basis swaps constitute 73 Bcf and volumes associated with price stabilization activities of the Natural Gas Distribution business segment comprise 46 Bcf.

(3)

The net of total non-trading derivative assets and liabilities is a $7 million liability as shown on CERC’s Condensed Consolidated Balance Sheets, and is comprised of the natural gas contracts derivative assets and liabilities separately shown above offset by collateral netting of $154 million.

For CERC’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 these contracts are recorded as net regulatory assets/liabilities. Realized and unrealized gains

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and losses on other derivatives are recognized in 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
		Three Months Ended March 31,
Total derivatives not designated as hedging instruments	Income Statement Location	2009			2010
		(in millions)
Natural gas contracts	Gains (Losses) in Revenue	$	77		$	44
Natural gas contracts (1)	Gains (Losses) in Expense: Natural Gas		(149	)		(61	)
Total		$	(72	)	$	(17	)

_________

(1)

The Gains (Losses) in Expense: Natural Gas includes $(78) and $(25) million of costs for the three months ended March 31, 2009 and 2010, respectively, associated with price stabilization activities of the Natural Gas Distribution business segment that will be ultimately recovered/refunded through purchased gas adjustments.

CERC enters into financial derivative contracts containing material adverse change provisions. These provisions require CERC to post additional collateral if the Standard & Poor’s Rating Services or Moody’s Investors Service, Inc. credit rating of CERC 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, 2010 is $173 million compared to $140 million at December 31, 2009. The aggregate fair value of assets that are already posted as collateral at March 31, 2010 is $92 million compared to $65 million at December 31, 2009. If all derivative contracts (in a net liability position) containing credit risk contingent features were triggered at Mar ch 31, 2010, $79 million of additional assets would be required to be posted as collateral compared to $75 million at December 31, 2009.

(6)	Fair Value Measurements

Assets and liabilities are recorded at fair value in the Condensed Consolidated Balance Sheets and are categorized based upon the level of judgment associated with the inputs used to measure their value. Hierarchical levels, as defined in this guidance 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. A market approach is utilized to value CERC’s Level 2 assets or liabilities.

Level 3: Inputs are unobservable for the asset or liability, and include situations where there is little, if any, market activity for the asset or liability. 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 CERC’s judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. CERC develops these inputs based on the best information available, including CERC’s own data. A market approach is utilized to value CERC’s Level 3 asset s or liabilities. CERC’s Level 3 derivative instruments primarily consist of options that are not traded on recognized exchanges and are valued using option pricing models.

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CERC determines the appropriate level for each financial asset and liability on a quarterly basis and recognizes any transfers at the end of the reporting period. For the quarter ended March 31, 2010, there were no significant transfers between levels.

The following tables present information about CERC’s assets and liabilities (including derivatives that are presented net) measured at fair value on a recurring basis as of December 31, 2009 and March 31, 2010, and indicate the fair value hierarchy of the valuation techniques utilized by CERC to determine such fair value.

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Netting Adjustments (1)			Balance as of December 31, 2009
	(in millions)
Assets
Corporate equities	$	1	$	—	$	—	$	—		$	1
Investments in money market funds		11		—		—		—			11
Derivative assets		1		77		5		(29	)		54
Total assets	$	13	$	77	$	5	$	(29	)	$	66
Liabilities
Derivative liabilities	$	12	$	194	$	11	$	(124	)	$	93
Total liabilities	$	12	$	194	$	11	$	(124	)	$	93

_________

(1)

Amounts represent the impact of legally enforceable master netting agreements that allow CERC to settle positive and negative positions and also include cash collateral of $95 million posted with the same counterparties.

	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, 2010
	(in millions)
Assets
Corporate equities	$	2	$	—	$	—	$	—		$	2
Investments in money market funds		11		—		—		—			11
Derivative assets		—		94		6		(22	)		78
Total assets	$	13	$	94	$	6	$	(22	)	$	91
Liabilities
Derivative liabilities	$	15	$	244	$	2	$	(176	)	$	85
Total liabilities	$	15	$	244	$	2	$	(176	)	$	85

_________

(1)

Amounts represent the impact of legally enforceable master netting agreements that allow CERC to settle positive and negative positions and also include cash collateral of $154 million posted with the same counterparties.

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

	Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Derivative assets and liabilities, net
	Three Months Ended March 31,
	2009			2010
	(in millions)
Beginning balance	$	(58	)	$	(6	)
Total unrealized gains or (losses):
Included in earnings		(3	)		2
Included in regulatory assets		(17	)		(1	)
Total purchases, sales, other settlements, net:
Included in earnings		2			—
Included in regulatory assets		50			9
Ending balance	$	(26	)	$	4
The amount of total gains(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	)	$	2

(7)

Goodwill

Goodwill by reportable business segment as of both December 31, 2009 and March 31, 2010 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,
	2009		2010
	(in millions)
Net income	$	95	$	106
Other comprehensive income:
Adjustment to pension and other postretirement plans (net of tax)		—		—
Other comprehensive income		—		—
Comprehensive income	$	95	$	106

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

	December 31, 2009			March 31, 2010
	(in millions)
Adjustment to pension and other postretirement plans	$	(4	)	$	(4	)
Total accumulated other comprehensive loss	$	(4	)	$	(4	)

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(9)	Related Party Transactions

CERC participates in a “money pool” through which it can borrow or invest on a short-term basis. Funding needs are aggregated and external borrowing or investing is based on the net cash position. The net funding requirements of the money pool are expected to be met with borrowings under CenterPoint Energy’s revolving credit facility or the sale of CenterPoint Energy’s commercial paper. CERC had money pool borrowings of $432 million and $292 million at December 31, 2009 and March 31, 2010, respectively, which are included in accounts and notes payable—affiliated companies in the Condensed Consolidated Balance Sheets.

For both the three months ended March 31, 2009 and 2010, CERC had net interest expense of less than $1 million related to affiliate borrowings.

CenterPoint Energy provides some corporate services to CERC. The costs of services have been charged directly to CERC using methods that management believes are reasonable. These methods include negotiated usage rates, dedicated asset assignment and proportionate corporate formulas based on operating expenses, assets, gross margin, employees and a composite of assets, gross margin and employees. These charges are not necessarily indicative of what would have been incurred had CERC not been an affiliate. Amounts charged to CERC for these services were $37 million for both the three months ended March 31, 2009 and 2010, and are included primarily in operation and maintenance expenses.

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

(a) Short-term Borrowings

Receivables Facility. On October 9, 2009, CERC amended its receivables facility to extend the termination date to October 8, 2010. Availability under CERC’s 364-day receivables facility now ranges from $150 million to $375 million, reflecting seasonal changes in receivables balances. As of December 31, 2009 and March 31, 2010, the facility size was $150 million and $375 million, respectively. As of both December 31, 2009 and March 31, 2010, there were no advances under the receivables facility.

Inventory Financing. In October 2009, Gas Operations entered into asset management agreements associated with its utility distribution service in Arkansas, north Louisiana and Oklahoma. Pursuant to the provisions of the agreements, Gas Operations sold $104 million of its natural gas in storage and agreed to repurchase an equivalent amount of natural gas during the 2009-2010 winter heating season at the same cost, plus a financing charge. This transaction was accounted for as a financing and a principal obligation of $55 million and $2 million remained as of December 31, 2009 and March 31, 2010, respectively.

Also in October 2009, Gas Operations entered into asset management agreements associated with its utility distribution service in south Louisiana, Mississippi and Texas. In connection with these asset management agreements, Gas Operations exchanged natural gas in storage for the right to receive an equivalent amount of natural gas during the 2009-2010 winter heating season. Although title to the natural gas in storage was transferred to the third party, the natural gas continues to be accounted for as inventory due to the right to receive an equivalent amount of natural gas during the current winter heating season. As of December 31, 2009 and March 31, 2010, CERC’s Condensed Consolidated Balance Sheets reflect $10 million and $-0-, respectively, in inventory related to these agreements.

(b) Long-term Debt

Convertible Subordinated Debentures. In January 2010, CERC Corp. redeemed $45 million of its outstanding 6% convertible subordinated debentures due 2012 at 100% of the principal amount plus accrued and unpaid interest to the redemption date.

Revolving Credit Facility. As of both December 31, 2009 and March 31, 2010, CERC Corp. had no outstanding borrowings under its $915 million credit facility. There was no commercial paper outstanding that would have been backstopped by CERC Corp.’s credit facility as of December 31, 2009 and March 31, 2010. CERC Corp. was in compliance with all debt covenants as of March 31, 2010.

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CERC Corp.’s $915 million credit facility’s first drawn cost is the London Interbank Offered Rate (LIBOR) plus 45 basis points based on CERC Corp.’s current credit ratings. The facility contains a debt to total capitalization covenant.

Under CERC Corp.’s $915 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 CERC Corp.’s credit rating.

(11)	Commitments and Contingencies

(a) Natural Gas Supply Commitments

Natural gas supply commitments include natural gas contracts related to CERC’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 CERC’s Condensed Consolidated Balance Sheets as of December 31, 2009 and March 31, 2010 as these contracts meet the 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, 2010, minimum payment obligations for natural gas supply commitments are approximately $308 million for the remaining nine months in 2010 , $484 million in 2011, $405 million in 2012, $346 million in 2013, $254 million in 2014 and $527 million after 2014.

(b) Capital Commitments

Long-Term Gas Gathering and Treating Agreements. In September 2009, CenterPoint Energy Field Services, Inc. (CEFS), a wholly-owned natural gas gathering and treating subsidiary of CERC Corp., entered into long-term agreements with an indirect wholly-owned subsidiary of Encana Corporation (Encana) and an indirect wholly-owned subsidiary of Royal Dutch Shell plc (Shell) to provide gathering and treating services for their natural gas production from certain Haynesville Shale and Bossier Shale formations in Louisiana. CEFS also acquired jointly-owned gathering facilities from Encana and Shell in De Soto and Red River parishes in northwest Louisiana. Each of the agreements includes acreage dedication and volume commitments for which CEFS has rights to gather Shell’s and Encana’s natural gas production from the dedicated areas. The gathering facilities are known as the “Magnolia Gathering System.”

In connection with the agreements, CEFS commenced gathering and treating services utilizing the acquired facilities. CEFS is expanding the acquired facilities in order to gather and treat up to 700 million cubic feet (MMcf) per day of natural gas and expects to place those facilities in service by the end of 2010. CEFS estimates that the purchase of existing facilities and construction to gather 700 MMcf per day will cost up to $325 million. As of March 31, 2010, approximately $260 million has been spent on this project, including the purchase of existing facilities.

Under the agreements, Encana or Shell can elect to require CEFS to further expand the facilities in order to gather and treat an additional volume of up to 1 Bcf per day, and in March 2010, Encana and Shell exercised initial expansion elections to increase gathering capacity by 200 MMcf per day to 900 MMcf. Total capital expenditures for this expansion are estimated to be $50 million to $70 million, and the increased capacity is expected to be in service by the first quarter of 2011. In connection with the expansion, Encana and Shell each made incremental volume commitments for the capacity expansion.

If Encana and Shell elect expansion of the project to gather and process additional future volumes of up to 1 Bcf per day (including the 200 MMcf per day already elected), CEFS estimates that the expansion would cost as much as $300 million, and Encana and Shell would provide incremental volume commitments.

In April 2010, CEFS entered into additional long-term agreements with Encana and Shell to provide gathering and treating services for their natural gas production from the Haynesville Shale and Bossier Shale formations in Texas and Louisiana. Pursuant to the agreements, CEFS has also acquired existing jointly-owned gathering facilities (the Olympia Gathering System) from Encana and Shell in De Soto and Red River parishes in northwest Louisiana.

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CEFS has integrated the acquired facilities with CEFS’s Magnolia Gathering System, allowing CEFS to commence gathering and treating services immediately for up to 150 MMcf per day of natural gas. Under the terms of the agreements, CEFS will expand the acquired facilities to gather and treat up to 580 MMcf per day of natural gas. Each of the agreements includes volume commitments and dedicated acreage for which CEFS has exclusive rights to gather Shell’s and Encana’s natural gas production.

New construction to reach capacity of 580 MMcf per day includes more than 180 miles of pipelines, over 8,000 horsepower of compression and over 680 MMcf per day of treating capacity.

CEFS estimates that the capital cost to purchase the existing facilities and construct new facilities for the Olympia Gathering System to gather 580 MMcf per day will be as much as $400 million. If Encana and Shell elect, CEFS will expand the project to gather and process additional future volumes of up to 520 MMcf per day, for a total Olympia Gathering System capacity of up to 1.1 Bcf per day. CEFS estimates that an expansion to process 1.1 Bcf would cost as much as an additional $200 million. Encana and Shell would provide incremental volume commitments in connection with expansions of the Olympia Gathering System.

Legal Matters

Gas Market Manipulation Cases. CenterPoint Energy or its predecessor, Reliant Energy, Incorporated (Reliant Energy), and certain of their former subsidiaries are named as defendants in several lawsuits described below. Under a master separation agreement between CenterPoint Energy and RRI (formerly known as Reliant Resources, Inc. and Reliant Energy, Inc.), 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 participan ts 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 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. CenterPoint Energy and its affiliates have been released or dismissed from all but two of such cases. CenterPoint Energy Services, Inc. (CES), a subsidiary of CERC Corp., is a defendant in a case now pending in federal c ourt in 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 appealed the dismissal in March 2010 to the Nevada Supreme Court. CenterPoint Energy believes that neither it nor CES is a proper defendant in these remaining cases and will continue to pursue dismissal from those cases. CenterPoint Energy does not expect the ultimate outcome of these remaining matters to have a material impact on its financial condition, results of operations or cash flows.

In May 2009, RRI sold 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. In April 2010, RRI announced its plan to merge with Mirant Corporation in an all-stock transaction. Neither the sale of the retail business nor the merger with Mirant Corporation, if ultimately finalized, alters RRI’s contractual obligations to indemnify CenterPoint Energy and its subsidiaries 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 discussed below under Guaranties.

Natural Gas Measurement Lawsuits. 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 CE RC Corp.

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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. In September 2009, the district court in Stevens County, Kansas, denied plaintiffs’ request for class certification of their case and, in March 2010, denied the plaintiffs’ request for reconsideration of that order.

CERC believes that there has been no systematic mismeasurement of gas and that these lawsuits are without merit. CERC and CenterPoint Energy do not expect the ultimate outcome of the lawsuits to have a material impact on the financial condition, results of operations or cash flows of either CenterPoint Energy or CERC.

Environmental Matters

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

At March 31, 2010, CERC 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. CERC has utilized an environmental expense tracker mechanism in its rates in Minnesota to recover estimated costs in excess of insurance recovery. In January 2010, as part of its Minnesota rate case decision, the MPUC eliminated the environmental expense tracker mechan ism and ordered amounts previously collected from ratepayers and related carrying costs refunded to customers. As of March 31, 2010, the balance in the environmental expense tracker account was $8.3 million. The MPUC provided for the inclusion in rates of approximately $285,000 annually to fund normal on-going remediation costs. CERC was not required to refund to customers the amount collected from insurance companies, $5.0 million at March 31, 2010, to be used to mitigate future environmental costs. The MPUC further gave assurance that any reasonable and prudent environmental clean-up costs CERC incurs in the future will be rate-recoverable under normal regulatory principles and procedures. This provision had no impact on earnings.

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 CERC or may have been owned by one of its former affiliates. CERC 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 CERC or its divisions. CERC 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 would be required to determine if other p otentially responsible parties, including CERC, would have to contribute to that remediation. In September 2009, the federal district court granted CERC’s motion for summary judgment in the proceeding. Although it is likely that the plaintiff will pursue an appeal from that dismissal, further action will not be taken until the district court disposes of claims against other defendants in the case. CERC 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. CERC and CenterPoint Energy do not expect the ultimate outcome to have a material adverse impact on the financial condition, results of operations or cash flows of either CenterPoint Energy or CERC.

Mercury Contamination. CERC'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. CERC has found this type of contamination at some sites in the past, and CERC 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,

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based on CERC's experience and that of others in the natural gas industry to date and on the current regulations regarding remediation of these sites, CERC 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 CERC’s predecessors have contained asbestos insulation and other asbestos-containing materials. CERC 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. CERC anticipates that additional claims like those received may be asserted in the future. Although their ultimate outcome cannot be predicted at this time, CERC 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 its financial condition, results of operations or cash flows.

Groundwater Contamination Litigation. Predecessor entities of CERC, along with several other entities, are defendants in litigation, St. Michel Plantation, LLC, et al, v. White, et al., pending in civil district court in Orleans Parish, Louisiana. In the lawsuit, the plaintiffs allege that their property in Terrebonne Parish, Louisiana suffered salt water contamination as a result of oil and gas drilling activities conducted by the defendants. Although a predecessor of CERC held an interest in two oil and gas leases on a portion of the property at issue, neither it nor any other CERC entities drilled or conducted other oil and gas operations on those leases. In January 2009, CERC and the plaint iffs reached agreement on the terms of a settlement that, if ultimately approved by the Louisiana Department of Natural Resources, is expected to resolve this litigation. CERC 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 CERC has received notices from regulatory authorities or others regarding its status as a PRP in connection with sites found to require remediation due to the presence of environmental contaminants. In addition, CERC has been named from time to time as a defendant in litigation related to such sites. Although the ultimate outcome of such matters cannot be predicted at this time, CERC does not expect, based on its experience to date, these matters, either individually or in the aggregate, to have a material adverse effect on its financial condition, results of operations or cash flows.

Other Proceedings

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

(d) Guaranties

Prior to CenterPoint Energy’s distribution of its ownership in RRI to its shareholders, CERC had guaranteed certain contractual obligations of what became RRI’s trading subsidiary. When the companies separated, RRI agreed to secure CERC against obligations under the guaranties RRI had been unable to extinguish by the time of separation. Pursuant to such agreement, as amended in December 2007, RRI has agreed to provide to CERC cash or letters of credit as security against CERC’s obligations under its remaining guaranties for demand charges under certain gas transportation agreements if and to the extent changes in market conditions expose CERC to a risk of loss on those guaranties. The present value of the demand charges under these transportation contracts, which will be effective until 2018, w as approximately $91 million as of March 31, 2010. As of March 31, 2010, RRI was not required to provide security to CERC. If RRI should fail to perform the contractual obligations, CERC could have to honor its guarantee and, in such event, collateral provided as security may be insufficient to satisfy CERC’s obligations.

(12)	Income Taxes

During the three months ended March 31, 2009 and 2010, the effective tax rate was 41% and 48%, respectively. The most significant item affecting the comparability of the effective tax rate is a non-cash, $19 million increase in the 2010 income tax expense as a result of a change in tax law upon the enactment in March 2010 of the Patient

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Protection and Affordable Care Act and the related Health Care and Education Reconciliation Act of 2010. Additionally, the comparability of the effective tax rate is affected by a $4 million increase in the 2009 income tax expense related to a state tax examination.

The change in tax law, which becomes effective for tax years beginning after December 31, 2012, eliminates the tax deductibility of the portion of retiree health care costs which are reimbursed by Medicare Part D subsidies. Based upon the actuarially determined net present value of lost future retiree health care deductions related to the subsidies, CERC reduced its deferred tax asset related to future retiree health care deductions by approximately $21 million as of March 31, 2010. The portion of the reduction that CERC believes will be recovered through the regulatory process, or approximately $2 million, has been recorded as a regulatory asset. The regulatory assets have also been increased by approximately $1 million related to the recovery of CERC’s income taxes. The remaining $19 m illion of the reduction in CERC’s deferred tax asset has been reflected as a charge to income tax expense.

The following table summarizes CERC’s unrecognized tax benefits at December 31, 2009 and March 31, 2010:

	December 31, 2009			March 31, 2010
	(in millions)
Unrecognized tax benefits	$	6		$	5
Portion of unrecognized tax benefits that, if recognized, would reduce the effective income tax rate		—			—
Interest receivable accrued on unrecognized tax benefits		(5	)		(5	)

During the three months ended March 31, 2010, the Internal Revenue Service notified CenterPoint Energy that it would perform an examination of CenterPoint Energy’s 2008 consolidated federal income tax return of which CERC is a member.

(13)	Estimated Fair Value of Financial Instruments

The fair values of cash and cash equivalents and short-term borrowings are estimated to be approximately equivalent to carrying amounts and have been excluded from the table below. The fair values of non-trading derivative assets and liabilities are stated at fair value and are excluded from the table below. The fair value of each debt instrument is determined by multiplying the principal amount of each debt instrument by the market price.

	December 31, 2009				March 31, 2010
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)
Financial liabilities:
Long-term debt	$	2,786	$	2,969	$	2,742	$	2,953

(14)	Reportable Business Segments

Because CERC is an indirect wholly owned subsidiary of CenterPoint Energy, CERC’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. CERC uses operating income as the measure of profit or loss for its business segments.

CERC’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 rate-regulated 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 CERC’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, processing and treating operations. Our Other Operations business segment includes unallocated corporate costs and inter-segment eliminations.

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

	For the Three Months Ended March 31, 2009
	Revenues from External Customers		Net Intersegment Revenues			Operating Income (Loss)			Total Assets as of December 31, 2009
Natural Gas Distribution	$	1,418	$	3		$	118		$	4,535
Competitive Natural Gas Sales and Services		760		5			2			1,176
Interstate Pipelines		117		36			69			3,484
Field Services		56		1			26			1,045
Other Operations		—		—			(1	)		800
Eliminations		—		(45	)		—			(1,256	)
Consolidated	$	2,351	$	—		$	214		$	9,784

	For the Three Months Ended March 31, 2010
	Revenues from External Customers		Net Intersegment Revenues			Operating Income (Loss)			Total Assets as of March 31, 2010
Natural Gas Distribution	$	1,533	$	4		$	139		$	4,597
Competitive Natural Gas Sales and Services		844		8			15			1,215
Interstate Pipelines		103		35			72			3,526
Field Services		58		10			23			1,199
Other Operations		—		—			(1	)		883
Eliminations		—		(57	)		—			(1,641	)
Consolidated	$	2,538	$	—		$	248		$	9,779

(15)	Other Current Assets and Liabilities

Included in other current assets on the Condensed Consolidated Balance Sheets at December 31, 2009 and March 31, 2010 was $80 million and $121 million, respectively, of under-recovered gas cost. Included in other current liabilities on the Condensed Consolidated Balance Sheets at December 31, 2009 and March 31, 2010 was $70 million and $195 million, respectively, of over-recovered gas cost.

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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, 2009 (2009 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, 2009 and the three months ended March 31, 2010. Reference is made to “Management’s Narrative Analysis of Results of Operations” in Item 7 of our 2009 Form 10-K.

EXECUTIVE SUMMARY

Recent Events

Long-Term Gas Gathering and Treating Agreements

In September 2009, CenterPoint Energy Field Services, Inc. (CEFS), a wholly-owned natural gas gathering and treating subsidiary of CERC Corp., entered into long-term agreements with an indirect wholly-owned subsidiary of Encana Corporation (Encana) and an indirect wholly-owned subsidiary of Royal Dutch Shell plc (Shell) to provide gathering and treating services for their natural gas production from certain Haynesville Shale and Bossier Shale formations in Louisiana. CEFS also acquired jointly-owned gathering facilities from Encana and Shell in De Soto and Red River parishes in northwest Louisiana. Each of the agreements includes acreage dedication and volume commitments for which CEFS has rights to gather Shell’s and Encana’s natural gas production from the dedicated areas. The gathering facilities a re known as the “Magnolia Gathering System.”

Under the agreements, Encana or Shell can elect to require CEFS to further expand the facilities in order to gather and treat an additional volume of up to 1 billion cubic feet (Bcf) per day, and in March 2010, Encana and Shell exercised initial expansion elections to increase gathering capacity by 200 MMcf per day to 900 MMcf. Total capital expenditures for this expansion are estimated to be $50 million to $70 million, and the increased capacity is expected to be in service by the first quarter of 2011. In connection with the expansion, Encana and Shell each made incremental volume commitments for the capacity expansion.

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gas. Each of the agreements includes volume commitments and dedicated acreage for which CEFS has exclusive rights to gather Shell’s and Encana’s natural gas production.

New construction to reach capacity of 580 MMcf per day includes more than 180 miles of pipelines, over 8,000 horsepower of compression and over 680 MMcf per day of treating capacity.

Debt Transactions

In January 2010, we redeemed $45 million of our outstanding 6% convertible subordinated debentures due 2012 at 100% of the principal amount plus accrued and unpaid interest to the redemption date.

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 2009 Form 10-K.

The following table sets forth our consolidated results of operations for the three months ended March 31, 2009 and 2010, followed by a discussion of our consolidated results of operations.

	Three Months Ended March 31,
	2009			2010
	(in millions)
Revenues	$	2,351		$	2,538
Expenses:
Natural gas		1,789			1,935
Operation and maintenance		233			232
Depreciation and amortization		57			60
Taxes other than income taxes		58			63
Total expenses		2,137			2,290
Operating Income		214			248
Interest and other finance charges		(54	)		(51	)
Equity in earnings of unconsolidated affiliates		—			5
Other income, net		1			—
Income Before Income Taxes		161			202
Income tax expense		(66	)		(96	)
Net Income	$	95		$	106

Three months ended March 31, 2010 compared to three months ended March 31, 2009

We reported net income of $106 million for the three months ended March 31, 2010 as compared to $95 million for the same period in 2009. The increase in net income of $11 million was primarily due to a $34 million increase in operating income from our business segments as discussed below, a $5 million increase in equity in earnings of unconsolidated affiliates and a $3 million decrease in interest and other finance charges, partially offset by a $30 million increase in income tax expense.

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Income Tax Expense. During the three months ended March 31, 2009 and 2010, the effective tax rate was 41% and 48%, respectively. The most significant item affecting the comparability of the effective tax rate is a non-cash, $19 million increase in the 2010 income tax expense as a result of a change in tax law upon the enactment in March 2010 of the Patient Protection and Affordable Care Act and the related Health Care and Education Reconciliation Act of 2010. Additionally, the comparability of the effective tax rate is affected by a $4 million increase in the 2009 income tax expense related to a state tax examination.

The change in tax law, which becomes effective for tax years beginning after December 31, 2012, eliminates the tax deductibility of the portion of retiree health care costs which are reimbursed by Medicare Part D subsidies. Based upon the actuarially determined net present value of lost future retiree health care deductions related to the subsidies, CERC reduced its deferred tax asset related to future retiree health cost deductions by approximately $21 million as of March 31, 2010. The portion of the reduction that CERC believes will be recovered through the regulatory process, or approximately $2 million, has been recorded as a regulatory asset. The regulatory assets have also been increased by approximately $1 million related to the recovery of CERC’s income taxes. The remaining $19 m illion of the reduction in CERC’s deferred tax asset has been reflected as a charge to income tax expense.

RESULTS OF OPERATIONS BY BUSINESS SEGMENT

The following table presents operating income (loss) for each of our business segments for the three months ended March 31, 2009 and 2010, 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,
	2009			2010
	(in millions)
Natural Gas Distribution	$	118		$	139
Competitive Natural Gas Sales and Services		2			15
Interstate Pipelines		69			72
Field Services		26			23
Other Operations		(1	)		(1	)
Total Consolidated Operating Income	$	214		$	248

Natural Gas Distribution

For information regarding factors that may affect the future results of operations of our Natural Gas Distribution business segment, please read "Risk Factors ─ Risk Factors Affecting Our Businesses," "─ Risk Factors Associated with Our Consolidated Financial Condition" and "─ Other Risks" in Item 1A of Part I of our 2009 Form 10-K.

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The following table provides summary data of our Natural Gas Distribution business segment for the three months ended March 31, 2009 and 2010 (in millions, except throughput and customer data):

	Three Months Ended March 31,
	2009		2010
Revenues	$	1,421	$	1,537
Expenses:
Natural gas		1,045		1,139
Operation and maintenance		169		167
Depreciation and amortization		40		40
Taxes other than income taxes		49		52
Total expenses		1,303		1,398
Operating Income	$	118	$	139

Throughput (in Bcf):
Residential		78		96
Commercial and industrial		77		87
Total Throughput		155		183

Number of customers at period end:
Residential		2,996,455		3,012,856
Commercial and industrial		246,405		246,676
Total		3,242,860		3,259,532

Three months ended March 31, 2010 compared to three months ended March 31, 2009

Our Natural Gas Distribution business segment reported operating income of $139 million for the three months ended March 31, 2010 compared to $118 million for the three months ended March 31, 2009. Operating income increased $21 million primarily as a result of increased margin (revenue less cost of natural gas) and lower bad debt expense. The increase in margin ($22 million) is due to increased use ($9 million), primarily caused by colder weather, and higher transportation ($4 million), non-utility ($3 million) and other miscellaneous revenues ($4 million). Revenues related to both energy efficiency programs and gross receipts taxes are substantially offset by the related expenses. Operation and maintenance expense declined $2 million due to lowe r bad debt expense ($5 million) related to improved collection efforts and lower pension expense ($2 million), partially offset by higher labor costs ($2 million) and other expense increases ($3 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 Businesses," "─ Risk Factors Associated with Our Consolidated Financial Condition" and "─ Other Risks" in Item 1A of Part I of our 2009 Form 10-K.

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The following table provides summary data of our Competitive Natural Gas Sales and Services business segment for the three months ended March 31, 2009 and 2010 (in millions, except throughput and customer data):

	Three Months Ended March 31,
	2009		2010
Revenues	$	765	$	852
Expenses:
Natural gas		752		826
Operation and maintenance		10		9
Depreciation and amortization		1		1
Taxes other than income taxes		—		1
Total expenses		763		837
Operating Income	$	2	$	15

Throughput (in Bcf):		141		141

Number of customers at period end		10,862		11,369

Three months ended March 31, 2010 compared to three months ended March 31, 2009

Our Competitive Natural Gas Sales and Services business segment reported operating income of $15 million for the three months ended March 31, 2010 compared to $2 million for the three months ended March 31, 2009. The increase in operating income of $13 million is primarily due to the favorable impact of the mark-to-market valuation for non-trading financial derivatives for 2010 of $3 million versus an unfavorable impact of $19 million for the same period in 2009. A further favorable impact of $5 million is attributable to the $6 million write down of gas in the first quarter of 2009 to the lower of cost or market as compared to a write down of less than $1 million in the first quarter of 2010. Offsetting these favorable impacts is a $14 million decrease in m argin attributable to reduced basis spreads on pipeline transport opportunities and decreased winter storage spreads.

Interstate Pipelines

For information regarding factors that may affect the future results of operations of our Interstate Pipelines business segment, please read "Risk Factors ─ Risk Factors Affecting Our Businesses," "─ Risk Factors Associated with Our Consolidated Financial Condition" and "─ Other Risks" in Item 1A of Part I of our 2009 Form 10-K.

The following table provides summary data of our Interstate Pipelines business segment for the three months ended March 31, 2009 and 2010 (in millions, except throughput data):

	Three Months Ended March 31,
	2009		2010
Revenues	$	153	$	138
Expenses:
Natural gas		29		10
Operation and maintenance		35		35
Depreciation and amortization		12		13
Taxes other than income taxes		8		8
Total expenses		84		66
Operating Income	$	69	$	72

Transportation throughput (in Bcf)		467		438

Three months ended March 31, 2010 compared to three months ended March 31, 2009

Our Interstate Pipeline business segment reported operating income of $72 million for the three months ended March 31, 2010 compared to $69 million for the three months ended March 31, 2009. Margins (revenues less natural gas costs) increased $4 million primarily due to new contracts on the Carthage to Perryville pipeline ($12 million), partially offset by reduced other transportation margins and ancillary services ($8 million). Depreciation and amortization increased by $1 million due to asset additions.

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Equity Earnings. In addition, this business segment recorded equity income (loss) of $(2) million and $3 million for the three months ended March 31, 2009 and 2010, respectively, from its 50% interest in the Southeast Supply Header (SESH), a jointly-owned pipeline that went into service in September 2008. The 2009 results include a non-cash pre-tax charge of $5 million to reflect SESH’s decision to discontinue the use of guidance for accounting for regulated operations. Excluding the effect of these adjustments, equity earnings from normal operations was $3 million in 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 Businesses," "─ Risk Factors Associated with Our Consolidated Financial Condition" and "─ Other Risks" in Item 1A of Part I of our 2009 Form 10-K.

The following table provides summary data of our Field Services business segment for the three months ended March 31, 2009 and 2010 (in millions, except throughput data):

	Three Months Ended March 31,
	2009		2010
Revenues	$	57	$	68
Expenses:
Natural gas		7		16
Operation and maintenance		19		21
Depreciation and amortization		4		6
Taxes other than income taxes		1		2
Total expenses		31		45
Operating Income	$	26	$	23

Gathering throughput (in Bcf)		104		128

Three months ended March 31, 2010 compared to three months ended March 31, 2009

Our Field Services business segment reported operating income of $23 million for the three months ended March 31, 2010 compared to $26 million for the three months ended March 31, 2009. Increased margin from new projects ($4 million) and increased natural gas liquids prices ($2 million) were more than offset by the effects of lower natural gas prices for retained volumes on the system ($3 million) and increased operating expenses ($5 million) associated with new projects.

Equity Earnings. In addition, this business segment recorded equity income of $2 million in both the three months ended March 31, 2009 and 2010 from its 50% interest in a jointly-owned gas processing plant. 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 2009 Form 10-K and “Cautionary Statement Regarding Forward-Looking Information.”

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LIQUIDITY AND CAPITAL RESOURCES

Our liquidity and capital requirements are affected primarily by our results of operations, capital expenditures, debt service requirements, tax payments, working capital needs, various regulatory actions and appeals relating to such actions. Our principal anticipated cash requirements for the remaining nine months of 2010 include approximately $768 million of capital expenditures.

We expect that borrowings under our credit facility, advances under our receivables facility, anticipated cash flows from operations and borrowings from affiliates will be sufficient to meet our anticipated cash needs for the remaining nine months of 2010. 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 RRI Energy, Inc. (formerly known as Reliant Energy, Inc. and Reliant Resources, Inc.) (RRI) to its shareholders, we had guaranteed certain contractual obligations of what became RRI’s trading subsidiary. When the companies separated, RRI agreed to secure us against obligations under the guaranties RRI had been unable to extinguish by the time of separation. Pursuant to such agreement, as amended in December 2007, RRI has agreed to provide to us cash or letters of credit as security against our obligations under our remaining guaranties for demand charges under certain gas purchase and transportation agreements if and to the extent changes in market conditions expose us to a risk of loss on those guaranties. As of March 31, 2010, RRI was n ot required to provide security to us. If RRI should fail to perform the contractual obligations, we could have to honor our guarantee and, in such event, collateral provided as security may be insufficient to satisfy our obligations.

Credit and Receivables Facilities. As of April 27, 2010, we had the following facilities (in millions):

Date Executed	Type of Facility	Size of Facility		Amount Utilized at April 27, 2010		Termination Date
June 29, 2007	Revolver	$	915	$	—	June 29, 2012
October 9, 2009	Receivables		375		—	October 8, 2010

CERC Corp.’s $915 million credit facility’s first drawn cost is the London Interbank Offered Rate (LIBOR) plus 45 basis points based on our current credit ratings. The facility contains covenants, including a debt to total capitalization covenant.

Under the credit facility, an additional utilization fee of 5 basis points applies to borrowings any time more than 50% of the facility is utilized. The spread to LIBOR and the utilization fee fluctuate based on our credit rating. Borrowings under the facility are subject to customary terms and conditions. However, there is no requirement that we make representations prior to borrowings as to the absence of material adverse changes or litigation that could be expected to have a material adverse effect. Borrowings under the credit facility are subject to acceleration upon the occurrence of events of default that we consider customary.

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

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CERC Corp.’s $915 million credit facility backstops a $915 million commercial paper program under which we began issuing commercial paper in February 2008. Our commercial paper is rated “P-3” by Moody’s Investors Service, Inc. (Moody’s), “A-2” by Standard & Poor’s Rating Services, a division of The McGraw Hill Companies (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 tim e or that one or more of these ratings will not be lowered or withdrawn entirely by a rating agency. We note that these credit ratings are not recommendations to buy, sell or hold our securities and may be revised or withdrawn at any time by the rating agency. Each rating should be evaluated independently of any other rating. Any future reduction or withdrawal of one or more of our credit ratings could have a material adverse impact on our ability to obtain short- and long-term financing, the cost of such financings and the execution of our commercial strategies.

Securities Registered with the SEC. At April 27, 2010, we had a shelf registration statement covering $500 million principal amount of senior debt securities.

Temporary Investments. As of April 27, 2010, 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 27, 2010, we had borrowings of $228 million from the money pool. The money pool may not provide sufficient funds to meet our cash needs.

Impact on Liquidity of a Downgrade in Credit Ratings. As of May 3, 2010, 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	Positive	BBB	Stable	BBB	Stable

_________

(1)

A Moody’s rating outlook is an opinion regarding the likely direction of a rating over the medium term.

(2)

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

(3)

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

A decline in these credit ratings could increase borrowing costs under our $915 million credit facility. If our credit ratings had been downgraded one notch by each of the three principal credit rating agencies from the ratings that existed at March 31, 2010, the impact on the borrowing costs under our credit facility would have been immaterial. A decline in credit ratings would also increase the interest rate on long-term debt to be issued in the capital markets and could negatively impact our ability to complete capital market transactions. Additionally, a decline in credit ratings could increase cash collateral requirements and reduce earnings of our Natural Gas Distribution and Competitive Natural Gas Sales and Services business segments.

We and our subsidiaries purchase natural gas from our largest supplier under supply agreements that contain an aggregate credit threshold of $120 million based on CERC Corp.’s S&P senior unsecured long-term debt rating of BBB. Under these agreements, we may need to provide collateral if the aggregate threshold is exceeded. Upgrades and downgrades from this BBB rating will increase and decrease the aggregate credit threshold accordingly.

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

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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, 2010, the amount posted as collateral aggregated approximately $179 million ($119 million of which is associated with price stabilization activities of our Natural Gas Distribution business segment). Should the credit ratings of CERC Corp. (as the credit support provider for CES) fall below certain levels, CES would be required to provide additional collateral up to the amount of its previously unsecured credit limit. We estimate that as of March 31, 2010, unsecured credit limits extended to CES by counterparties aggregate $243 million; however, utilized credit capacity was $81 million.

Pipeline tariffs and contracts typically provide that if the credit ratings of a shipper or the shipper’s guarantor drop below a threshold level, which is generally investment grade ratings from both Moody’s and S&P, cash or other collateral may be demanded from the shipper in an amount equal to the sum of three months’ charges for pipeline services plus the unrecouped cost of any lateral built for such shipper. If the credit ratings of CERC Corp. decline below the applicable threshold levels, we might need to provide cash or other collateral of as much as $184 million as of March 31, 2010. The amount of collateral will depend on seasonal variations in transportation levels.

Cross Defaults. Under CenterPoint Energy’s revolving credit facility, a payment default on, or a non-payment default that permits acceleration of, any indebtedness 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 March 31, 2010, 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 econo mic 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;

•

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

•

increased costs related to the acquisition of natural gas;

•

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

•

various regulatory actions;

•

increased capital expenditures required for new gas pipeline or field services projects;

•

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

•

the ability of RRI and its subsidiaries to satisfy their obligations in respect of RRI’s indemnity obligations to us and our subsidiaries or in connection with the contractual obligations to a third party pursuant to which we are their guarantor;

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•

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;

•

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

•

various other risks identified in “Risk Factors” in Item 1A of our 2009 Form 10-K.

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

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

NEW ACCOUNTING PRONOUNCEMENTS

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

Item 4T. CONTROLS AND PROCEDURES

In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our principal executive officer and principal financial officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of March 31, 2010 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 commun icated 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, 2010 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 2009 Form 10-K.

Item 1A. RISK FACTORS

There have been no material changes from the risk factors disclosed in our 2009 Form 10-K.

Item 5. OTHER INFORMATION

Our ratio of earnings to fixed charges for the three months ended March 31, 2009 and 2010 was 3.81 and 4.55, respectively. We do not believe that the ratios for these three-month periods are necessarily indicative 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

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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 13, 2010

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Index to Exhibits

The following exhibits are filed herewith:

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

Exhibit Number		Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference
3.1.1	─	Certificate of Incorporation of RERC Corp.	Form 10-K for the year ended December 31, 1997	1-13265	3(a)(1)
3.1.2	─	Certificate of Merger merging former NorAm Energy Corp. with and into HI Merger, Inc. dated August 6, 1997	Form 10-K for the year ended December 31, 1997	1-13265	3(a)(2)
3.1.3	─	Certificate of Amendment changing the name to Reliant Energy Resources Corp.	Form 10-K for the year ended December 31, 1998	1-13265	3(a)(3)
3.1.4	─	Certificate of Amendment changing the name to CenterPoint Energy Resources Corp.	Form 10-Q for the quarter ended June 30, 2003	1-13265	3(a)(4)
3.2	─	Bylaws of RERC Corp.	Form 10-K for the year ended December 31, 1997	1-13265	3(b)
4.1	─	$950,000,000 Second Amended and Restated Credit Agreement, dated as of June 29, 2007, among CERC Corp., as Borrower, and the banks named therein	CERC Corp.’s Form 10-Q for the quarter ended June 30, 2007	1-13265	4.1
+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

ex12.htm

Exhibit 12

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

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

COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES

(Millions of Dollars)

	Three Months Ended March 31,
	2009			2010

Net Income	$	95		$	106
Equity in earnings of unconsolidated affiliates, net of distributions		─			5
Income taxes		66			96
Capitalized interest		(1	)		(1	)
		160			206

Fixed charges, as defined:

Interest		54			51
Capitalized interest		1			1
Interest component of rentals charged to operating expense		2			6
Total fixed charges		57			58

Earnings, as defined	$	217		$	264

Ratio of earnings to fixed charges		3.81			4.55

ex31-1.htm

Exhibit 31.1

CERTIFICATIONS

I, David M. McClanahan, certify that:

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

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

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

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

(a)

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

(b)

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

(c)

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

(d)

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

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

(a)

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

(b)

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

Date: May 13, 2010

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

ex31-2.htm

Exhibit 31.2

CERTIFICATIONS

I, Gary L. Whitlock, certify that:

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

(a)

(b)

(c)

(d)

(a)

(b)

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

Date: May 13, 2010

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

ex32-1.htm

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of CenterPoint Energy Resources Corp. (the “Company”) on Form 10-Q for the quarter ended March 31, 2010 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, David M. McClanahan, Chief Executive Officer, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

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

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

/s/ David M. McClanahan
David M. McClanahan
President and Chief Executive Officer
May 13, 2010

ex32-2.htm

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of CenterPoint Energy Resources Corp. (the “Company”) on Form 10-Q for the quarter ended March 31, 2010 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, Gary L. Whitlock, Chief Financial Officer, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

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

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

/s/ Gary L. Whitlock
Gary L. Whitlock
Executive Vice President and Chief Financial Officer
May 13, 2010