UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

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

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2008

OR

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

FOR THE TRANSITION PERIOD FROM                      TO                     .

Commission file number 1-31447

CENTERPOINT ENERGY, INC.

(Exact name of registrant as specified in its charter)

Texas (State or other jurisdiction of incorporation or organization)		74-0694415 (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)

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

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

Large accelerated filer þ		Accelerated filer o		Non-accelerated filer o		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 o No þ

     As of March 31, 2008, CenterPoint Energy, Inc. had 328,265,076 shares of common stock outstanding, excluding 166 shares held as treasury stock.

 

 

CENTERPOINT ENERGY, INC.
QUARTERLY REPORT ON FORM 10-Q
FOR THE QUARTER ENDED MARCH 31, 2008

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION
Item 1. Financial Statements			1
Condensed Statements of Consolidated Income Three Months Ended March 31, 2007 and 2008 (unaudited)			1
Condensed Consolidated Balance Sheets December 31, 2007 and March 31, 2008 (unaudited)			2
Condensed Statements of Consolidated Cash Flows Three Months Ended March 31, 2007 and 2008 (unaudited)			4
Notes to Unaudited Condensed Consolidated Financial Statements			5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			23
Item 3. Quantitative and Qualitative Disclosures about Market Risk			35
Item 4. Controls and Procedures			36
PART II. OTHER INFORMATION
Item 1. Legal Proceedings			36
Item 1A. Risk Factors			36
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			37
Item 4. Submission of Matters to a Vote of Security Holders			37
Item 5. Other Information			38
Item 6. Exhibits			38
Articles of Amendment to Amended and Restated Articles of Incorporation
Computation of Ratios of Earnings to Fixed Charges
Certification of David M. McClanahan Pursuant to Rule 13a-14(a)/15d-14(a)
Certification of Gary L. Whitlock Pursuant to Rule 13a-14(a)/15d-14(a)
Certification of David M. McClanahan Pursuant to Section 1350
Certification of Gary L. Whitlock Pursuant to Section 1350
Risk Factors From the Form 10-K

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

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

     We have based our forward-looking statements on our management’s beliefs and assumptions based on information available to our management at the time the statements are made. We caution you that assumptions, beliefs, expectations, intentions and projections about future events may and often do vary materially from actual results. Therefore, we cannot assure you that actual results will not differ materially from those expressed or implied by our forward-looking statements.

     The following are some of the factors that could cause actual results to differ materially from those expressed or implied in forward-looking statements:

	•		the resolution of the true-up proceedings, including, in particular, the results of appeals to the courts regarding rulings obtained to date;
	•		state and federal legislative and regulatory actions or developments, including deregulation, re-regulation, environmental regulations, including regulations related to global climate change, and changes in or application of laws or regulations applicable to the various aspects of our business;
	•		timely and appropriate rate actions and increases, allowing recovery of costs and a reasonable return on investment;
	•		cost overruns on major capital projects that cannot be recouped in prices;
	•		industrial, commercial and residential growth in our service territory and changes in market demand and demographic patterns;
	•		the timing and extent of changes in commodity prices, particularly natural gas;
	•		the timing and extent of changes in the supply of natural gas;
	•		the timing and extent of changes in natural gas basis differentials;
	•		weather variations and other natural phenomena;
	•		changes in interest rates or rates of inflation;
	•		commercial bank and financial market conditions, our access to capital, the cost of such capital, and the results of our financing and refinancing efforts, including availability of funds in the debt capital markets;
	•		actions by rating agencies;
	•		effectiveness of our risk management activities;
	•		inability of various counterparties to meet their obligations to us;
	•		non-payment for our services due to financial distress of our customers, including Reliant Energy, Inc. (RRI);
	•		the ability of RRI and its subsidiaries to satisfy their other obligations to us, including indemnity obligations, or in connection with the contractual arrangements pursuant to which we are their guarantor;

	•		the outcome of litigation brought by or against us;
	•		our ability to control costs;
	•		the investment performance of our employee benefit plans;
	•		our potential business strategies, including acquisitions or dispositions of assets or businesses, which we cannot assure will be completed or will have the anticipated benefits to us;
	•		acquisition and merger activities involving us or our competitors; and
	•		other factors we discuss in “Risk Factors” in Item 1A of Part I of our Annual Report on Form 10-K for the year ended December 31, 2007, which is incorporated herein by reference, and other reports we file from time to time with the Securities and Exchange Commission.

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

PART I. FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

		Three Months Ended
		March 31,
		2007				2008
Revenues		$	3,106			$	3,363
Expenses:
Natural gas			2,150				2,393
Operation and maintenance			352				365
Depreciation and amortization			145				158
Taxes other than income taxes			106				111
Total			2,753				3,027
Operating Income			353				336
Other Income (Expense):
Loss on Time Warner investment			(44	)			(54	)
Gain on indexed debt securities			41				50
Interest and other finance charges			(123	)			(115	)
Interest on transition bonds			(31	)			(33	)
Other, net			6				13
Total			(151	)			(139	)
Income Before Income Taxes			202				197
Income tax expense			(72	)			(74	)
Net Income		$	130			$	123
Basic Earnings Per Share		$	0.41			$	0.38
Diluted Earnings Per Share		$	0.38			$	0.36

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

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

ASSETS

		December 31,				March 31,
		2007				2008
Current Assets:
Cash and cash equivalents		$	129			$	70
Investment in Time Warner common stock			357				303
Accounts receivable, net			910				1,097
Accrued unbilled revenues			558				455
Natural gas inventory			395				65
Materials and supplies			95				98
Non-trading derivative assets			38				59
Prepaid expenses and other current assets			306				204
Total current assets			2,788				2,351
Property, Plant and Equipment:
Property, plant and equipment			13,250				13,332
Less accumulated depreciation and amortization			3,510				3,530
Property, plant and equipment, net			9,740				9,802
Other Assets:
Goodwill			1,696				1,696
Regulatory assets			2,993				2,907
Non-trading derivative assets			11				22
Notes receivable from unconsolidated affiliates			148				150
Other			496				607
Total other assets			5,344				5,382
Total Assets		$	17,872			$	17,535

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

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS – (continued)
(Millions of Dollars)
(Unaudited)

LIABILITIES AND SHAREHOLDERS’ EQUITY

		December 31,				March 31,
		2007				2008
Current Liabilities:
Short-term borrowings		$	232			$	200
Current portion of transition bond long-term debt			159				186
Current portion of other long-term debt			1,156				724
Indexed debt securities derivative			261				211
Accounts payable			726				779
Taxes accrued			316				269
Interest accrued			170				145
Non-trading derivative liabilities			61				33
Accumulated deferred income taxes, net			350				367
Other			360				370
Total current liabilities			3,791				3,284
Other Liabilities:
Accumulated deferred income taxes, net			2,235				2,229
Unamortized investment tax credits			31				29
Non-trading derivative liabilities			14				4
Benefit obligations			499				493
Regulatory liabilities			828				795
Other			300				275
Total other liabilities			3,907				3,825
Long-term Debt:
Transition bonds			2,101				2,485
Other			6,263				6,061
Total long-term debt			8,364				8,546
Commitments and Contingencies (Note 10)
Shareholders’ Equity:
Common stock (322,718,785 shares and 328,265,076 shares outstanding at December 31, 2007 and March 31, 2008, respectively)			3				3
Additional paid-in capital			3,023				3,041
Accumulated deficit			(1,172	)			(1,109	)
Accumulated other comprehensive loss			(44	)			(55	)
Total shareholders’ equity			1,810				1,880
Total Liabilities and Shareholders’ Equity		$	17,872			$	17,535

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

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

		Three Months Ended March 31,
		2007				2008
Cash Flows from Operating Activities:
Net income		$	130			$	123
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization			145				158
Amortization of deferred financing costs			19				7
Deferred income taxes			(13	)			27
Unrealized loss on Time Warner investment			44				54
Unrealized gain on indexed debt securities			(41	)			(50	)
Changes in other assets and liabilities:
Accounts receivable and unbilled revenues, net			16				(84	)
Inventory			217				327
Accounts payable			(222	)			56
Fuel cost over recovery			23				29
Non-trading derivatives, net			18				28
Margin deposits, net			52				29
Interest and taxes accrued			(65	)			(72	)
Net regulatory assets and liabilities			22				14
Other current assets			25				34
Other current liabilities			(85	)			(63	)
Other assets			(4	)			(15	)
Other liabilities			(34	)			(47	)
Other, net			17				12
Net cash provided by operating activities			264				567
Cash Flows from Investing Activities:
Capital expenditures			(399	)			(187	)
Decrease (increase) in restricted cash of transition bond companies			5				(13	)
Increase in notes receivable from unconsolidated affiliates			—				(2	)
Investment in unconsolidated affiliates			—				(105	)
Other, net			(9	)			(5	)
Net cash used in investing activities			(403	)			(312	)
Cash Flows from Financing Activities:
Increase (decrease) in short-term borrowings, net			150				(32	)
Long-term revolving credit facilities, net			—				(231	)
Proceeds from commercial paper, net			—				35
Proceeds from long-term debt			400				488
Payments of long-term debt			(434	)			(515	)
Debt issuance costs			(6	)			—
Payment of common stock dividends			(54	)			(60	)
Proceeds from issuance of common stock, net			13				1
Other, net			3				—
Net cash provided by (used in) financing activities			72				(314	)
Net Decrease in Cash and Cash Equivalents			(67	)			(59	)
Cash and Cash Equivalents at Beginning of Period			127				129
Cash and Cash Equivalents at End of Period		$	60			$	70
Supplemental Disclosure of Cash Flow Information:
Cash Payments:
Interest, net of capitalized interest		$	177			$	173
Income taxes, net			34				39

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

CENTERPOINT ENERGY, INC. 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, Inc. are the condensed consolidated interim financial statements and notes (Interim Condensed Financial Statements) of CenterPoint Energy, Inc. and its subsidiaries (collectively, CenterPoint Energy, or the Company). The Interim Condensed Financial Statements are unaudited, omit certain financial statement disclosures and should be read with the Annual Report on Form 10-K of CenterPoint Energy for the year ended December 31, 2007 (CenterPoint Energy Form 10-K).

     Background. CenterPoint Energy, Inc. is a public utility holding company. The Company’s operating subsidiaries own and operate electric transmission and distribution facilities, natural gas distribution facilities, interstate pipelines and natural gas gathering, processing and treating facilities. As of March 31, 2008, the Company’s indirect wholly owned subsidiaries included:

	•		CenterPoint Energy Houston Electric, LLC (CenterPoint Houston), which engages in the electric transmission and distribution business in a 5,000-square mile area of the Texas Gulf Coast that includes Houston; and
	•		CenterPoint Energy Resources Corp. (CERC Corp., and, together with its subsidiaries, CERC), which owns and operates natural gas distribution systems in six states. Subsidiaries of CERC 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.

     Basis of Presentation. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

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

     For a description of the Company’s reportable business segments, reference is made to Note 13.

(2) New Accounting Pronouncements

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

     In February 2007, the FASB issued Statement of Financial Accounting Standard (SFAS) No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities, including an amendment of FASB Statement No. 115” (SFAS No. 159). SFAS No. 159 permits the Company to choose, at specified election dates, to measure eligible items at fair value (the “fair value option”). The Company would report unrealized gains and losses on items for which the fair value option has been elected in earnings at each subsequent reporting period. This accounting

standard is effective as of the beginning of the first fiscal year that begins after November 15, 2007 but is not required to be applied. The Company currently has no plans to apply SFAS No. 159.

     In December 2007, the FASB issued SFAS No. 141 (Revised 2007), “Business Combinations” (SFAS No. 141R). SFAS No. 141R will significantly change the accounting for business combinations. Under SFAS No. 141R, an acquiring entity will be required to recognize all the assets acquired and liabilities assumed in a transaction at the acquisition date fair value with limited exceptions. SFAS No. 141R also includes a substantial number of new disclosure requirements and applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. As the provisions of SFAS No. 141R are applied prospectively, the impact to the Company cannot be determined until applicable transactions occur.

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

     Effective January 1, 2008, the Company adopted SFAS No. 157, “Fair Value Measurements” (SFAS No. 157), which requires additional disclosures about the Company’s financial assets and liabilities that are measured at fair value. FASB Staff Position No. FAS 157-2 delays the effective date for SFAS No. 157 for nonfinancial assets and liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis, to fiscal years, and interim periods within those fiscal years, beginning after November 15, 2008. As defined in SFAS No. 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, valuation models are applied. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the price transparency for the instruments or market and the instruments’ complexity for disclosure purposes. Beginning in January 2008, assets and liabilities recorded at fair value in the Condensed Consolidated Balance Sheet are categorized based upon the level of judgment associated with the inputs used to measure their value. Hierarchical levels, as defined in SFAS No. 157 and directly related to the amount of subjectivity associated with the inputs to fair valuations of these assets and liabilities, are as follows: 

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

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

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

     The following table presents information about the Company’s assets and liabilities (including derivatives that are presented net) measured at fair value on a recurring basis as of March 31, 2008, and indicates the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair value.

		Quoted Prices in				Significant Other				Significant
		Active Markets				Observable				Unobservable								Balance
		for Identical Assets				Inputs				Inputs				Netting				as of
		(Level 1)				(Level 2)				(Level 3)				Adjustments (1)				March 31, 2008
										(in millions)
Assets
Corporate equities		$	305			$	—			$	—			$	—			$	305
Investments			74				—				—				(1	)			73
Derivative assets			1				103				4				(27	)			81
Total assets		$	380			$	103			$	4			$	(28	)		$	459
Liabilities
Indexed debt securities derivative		$	—			$	211			$	—			$	—			$	211
Derivative liabilities			3				60				2				(28	)			37
Total liabilities		$	3			$	271			$	2			$	(28	)		$	248

     The following table presents additional information about assets or liabilities, including derivatives that are measured at fair value on a recurring basis for which the Company has utilized Level 3 inputs to determine fair value, for the three months ended March 31, 2008:

		Fair Value Measurements
		Using Significant
		Unobservable Inputs
		(Level 3)
		Derivatives, net
		(in millions)
Beginning balance as of January 1, 2008		$	(3	)
Total gains or losses (realized and unrealized):
Included in earnings			6
Included in other comprehensive loss			—
Net transfers into level 3			—
Purchases, sales, other settlements, net			(1	)
Ending balance as of March 31, 2008		$	2
The amount of total gains or losses for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the reporting date		$	1

(3) Employee Benefit Plans

     The Company’s net periodic cost includes the following components relating to pension and postretirement benefits:

		Three Months Ended March 31,
		2007								2008
		Pension				Postretirement				Pension				Postretirement
		Benefits				Benefits				Benefits				Benefits
						(in millions)
Service cost		$	9			$	—			$	8			$	—
Interest cost			25				7				25				7
Expected return on plan assets			(37	)			(3	)			(37	)			(3	)
Amortization of prior service cost			(2	)			1				(2	)			1
Amortization of net loss			9				—				6				—
Amortization of transition obligation			—				2				—				2
Net periodic cost		$	4			$	7			$	—			$	7

     The Company expects to contribute approximately $8 million to its pension plans in 2008, of which $2 million had been contributed as of March 31, 2008.

     The Company expects to contribute approximately $21 million to its postretirement benefits plan in 2008, of which $6 million had been contributed as of March 31, 2008.

(4) Regulatory Matters

(a) Recovery of True-Up Balance

     In March 2004, CenterPoint Houston filed its true-up application with the Public Utility Commission of Texas (Texas Utility Commission), requesting recovery of $3.7 billion, excluding interest, as allowed under the Texas Electric Choice Plan (Texas electric restructuring law). In December 2004, the Texas Utility Commission issued its final order (True-Up Order) allowing CenterPoint Houston to recover a true-up balance of approximately $2.3 billion, which included interest through August 31, 2004, and provided for adjustment of the amount to be recovered to include interest on the balance until recovery, along with the principal portion of additional excess mitigation credits (EMCs) returned to customers after August 31, 2004 and in certain other respects.

     CenterPoint Houston and other parties filed appeals of the True-Up Order to a district court in Travis County, Texas. In August 2005, that court issued its judgment on the various appeals. In its judgment, the district court:

	•		reversed the Texas Utility Commission’s ruling that had denied recovery of a portion of the capacity auction true-up amounts;
	•		reversed the Texas Utility Commission’s ruling that precluded CenterPoint Houston from recovering the interest component of the EMCs paid to retail electric providers; and
	•		affirmed the True-Up Order in all other respects.

     The district court’s decision would have had the effect of restoring approximately $650 million, plus interest, of the $1.7 billion the Texas Utility Commission had disallowed from CenterPoint Houston’s initial request.

     CenterPoint Houston and other parties appealed the district court’s judgment to the Texas Third Court of Appeals, which issued its decision in December 2007. In its decision, the court of appeals:

	•		reversed the district court’s judgment to the extent it restored the capacity auction true-up amounts;
	•		reversed the district court’s judgment to the extent it upheld the Texas Utility Commission’s decision to allow CenterPoint Houston to recover EMCs paid to Reliant Energy, Inc. (RRI);
	•		ordered that the tax normalization issue described below be remanded to the Texas Utility Commission as requested by the Texas Utility Commission; and
	•		affirmed the district court’s judgment in all other respects.

     CenterPoint Houston and two other parties filed motions for rehearing with the court of appeals. On April 17, 2008, the court of appeals denied those motions and reissued substantially the same opinion as it had rendered in December 2007.  CenterPoint Houston now plans to seek further review by the Texas Supreme Court. Although the Company and CenterPoint Houston believe that CenterPoint Houston’s true-up request is consistent with applicable statutes and regulations and, accordingly, that it is reasonably possible that it will be successful in its further appeal, the Company can provide no assurance as to the ultimate court rulings on the issues to be considered in the appeal or with respect to the ultimate decision by the Texas Utility Commission on the tax normalization issue described below.

     To reflect the impact of the True-Up Order, in 2004 and 2005 the Company recorded a net after-tax extraordinary loss of $947 million. No amounts related to the district court’s judgment or the decision of the court of appeals have been recorded in the Company’s consolidated financial statements. However, if the court of appeals

decision is not reversed or modified as a result of further review by the Texas Supreme Court, the Company anticipates that it would be required to record an additional loss to reflect the court of appeals decision. The amount of that loss would depend on several factors, including ultimate resolution of the tax normalization issue described below and the calculation of interest on any amounts CenterPoint Houston ultimately is authorized to recover or is required to refund beyond the amounts recorded based on the True-up Order, but could range from $130 million to $350 million plus interest subsequent to December 31, 2007.

     In the True-Up Order, the Texas Utility Commission reduced CenterPoint Houston’s stranded cost recovery by approximately $146 million, which was included in the extraordinary loss discussed above, for the present value of certain deferred tax benefits associated with its former electric generation assets. The Company believes that the Texas Utility Commission based its order on proposed regulations issued by the Internal Revenue Service (IRS) in March 2003 which would have allowed utilities owning assets that were deregulated before March 4, 2003 to make a retroactive election to pass the benefits of Accumulated Deferred Investment Tax Credits (ADITC) and Excess Deferred Federal Income Taxes (EDFIT) back to customers. However, the IRS subsequently withdrew those proposed normalization regulations and in March 2008 adopted final regulations that would not permit CenterPoint Houston to pass the tax benefits back to customers without creating normalization violations. In addition, the Company received a Private Letter Ruling (PLR) from the IRS in August 2007, prior to adoption of the final regulations, that confirmed that the Texas Utility Commission’s order reducing CenterPoint Houston’s stranded cost recovery by $146 million for ADITC and EDFIT would cause normalization violations with respect to the ADITC and EDFIT. 

     If the Texas Utility Commission’s order relating to the ADITC reduction is not reversed or otherwise modified on remand so as to eliminate the normalization violation, the IRS could require the Company to pay an amount equal to CenterPoint Houston’s unamortized ADITC balance as of the date that the normalization violation is deemed to have occurred. In addition, the IRS could deny CenterPoint Houston the ability to elect accelerated tax depreciation benefits beginning in the taxable year that the normalization violation is deemed to have occurred. Such treatment, if required by the IRS, could have a material adverse impact on the Company’s results of operations, financial condition and cash flows in addition to any potential loss resulting from final resolution of the True-Up Order. However, the Company and CenterPoint Houston will continue to pursue a favorable resolution of this issue through the appellate or administrative process. Although the Texas Utility Commission has not previously required a company subject to its jurisdiction to take action that would result in a normalization violation, no prediction can be made as to the ultimate action the Texas Utility Commission may take on this issue on remand.

     The Texas electric restructuring law allowed the amounts awarded to CenterPoint Houston in the Texas Utility Commission’s True-Up Order to be recovered either through the issuance of transition bonds or through implementation of a competition transition charge (CTC) or both. Pursuant to a financing order issued by the Texas Utility Commission in March 2005 and affirmed by a Travis County district court, in December 2005 a subsidiary of CenterPoint Houston issued $1.85 billion in transition bonds with interest rates ranging from 4.84% to 5.30% and final maturity dates ranging from February 2011 to August 2020. Through issuance of the transition bonds, CenterPoint Houston recovered approximately $1.7 billion of the true-up balance determined in the True-Up Order plus interest through the date on which the bonds were issued.

     In July 2005, CenterPoint Houston received an order from the Texas Utility Commission allowing it to implement a CTC designed to collect the remaining $596 million from the True-Up Order over 14 years plus interest at an annual rate of 11.075% (CTC Order). The CTC Order authorized CenterPoint Houston to impose a charge on retail electric providers to recover the portion of the true-up balance not recovered through a financing order. The CTC Order also allowed CenterPoint Houston to collect approximately $24 million of rate case expenses over three years without a return through a separate tariff rider (Rider RCE). CenterPoint Houston implemented the CTC and Rider RCE effective September 13, 2005 and began recovering approximately $620 million. The return on the CTC portion of the true-up balance was included in CenterPoint Houston’s tariff-based revenues beginning September 13, 2005. Effective August 1, 2006, the interest rate on the unrecovered balance of the CTC was reduced from 11.075% to a weighted average cost of capital of 8.06% pursuant to a revised rule adopted by the Texas Utility Commission in June 2006.

     Certain parties appealed the CTC Order to a district court in Travis County. In May 2006, the district court issued a judgment reversing the CTC Order in three respects. First, the court ruled that the Texas Utility Commission had improperly relied on provisions of its rule dealing with the interest rate applicable to CTC

amounts. The district court reached that conclusion based on its belief that the Texas Supreme Court had previously invalidated that entire section of the rule. The 11.075% interest rate in question was applicable from the implementation of the CTC Order on September 13, 2005 until August 1, 2006, the effective date of the implementation of a new CTC in compliance with the revised rule discussed above. Second, the district court reversed the Texas Utility Commission’s ruling that allows CenterPoint Houston to recover through the Rider RCE the costs (approximately $5 million) for a panel appointed by the Texas Utility Commission in connection with the valuation of electric generation assets. Finally, the district court accepted the contention of one party that the CTC should not be allocated to retail customers that have switched to new on-site generation. The Texas Utility Commission and CenterPoint Houston disagree with the district court’s conclusions and, in May 2006, appealed the judgment to the Texas Third Court of Appeals, and if required, CenterPoint Houston plans to seek further review from the Texas Supreme Court. All briefs in the appeal have been filed, and oral arguments were held in December 2006. The ultimate outcome of this matter cannot be predicted at this time. However, the Company does not expect the disposition of this matter to have a material adverse effect on the Company’s or CenterPoint Houston’s financial condition, results of operations or cash flows.

     During the three months ended March 31, 2007 and 2008, CenterPoint Houston recognized approximately $11 million and $5 million, respectively, in operating income from the CTC, which was terminated in February 2008 when the transition bonds described below were issued. Additionally, during the three months ended March 31, 2007 and 2008, CenterPoint Houston recognized approximately $3 million and $2 million, respectively, of the allowed equity return not previously recorded.

     During the 2007 legislative session, the Texas legislature amended statutes prescribing the types of true-up balances that can be securitized by utilities and authorized the issuance of transition bonds to recover the balance of the CTC. In June 2007, CenterPoint Houston filed a request with the Texas Utility Commission for a financing order that would allow the securitization of the remaining balance of the CTC, adjusted to refund certain unspent environmental retrofit costs and to recover the amount of the final fuel reconciliation settlement. CenterPoint Houston reached substantial agreement with other parties to this proceeding, and a financing order was approved by the Texas Utility Commission in September 2007. In February 2008, a new special purpose subsidiary of CenterPoint Houston issued approximately $488 million of transition bonds pursuant to the financing order in two tranches with interest rates of 4.192% and 5.234% and final maturity dates of February 2020 and February 2023, respectively. Contemporaneously with the issuance of those bonds, the CTC was terminated and a transition charge was implemented.

     As of March 31, 2008, the Company had not recorded an allowed equity return of $218 million on CenterPoint Houston’s true-up balance because such return will be recognized as it is recovered in rates.

(b) Rate Cases

     Texas.  In March 2008, CERC Corp.’s natural gas distribution business (Gas Operations) filed a request to change its rates with the Railroad Commission of Texas (Railroad Commission) and the 47 cities in its Texas Coast service territory, an area consisting of approximately 230,000 customers in cities and communities on the outskirts of Houston.  The request seeks to establish uniform rates, charges and terms and conditions of service for the cities and environs of the Texas Coast service territory.  The effect of the requested rate changes will be to increase the Texas Coast service territory’s revenues by approximately $7 million per year.

     Minnesota.  In November 2006, the Minnesota Public Utilities Commission (MPUC) denied a request filed by Gas Operations for a waiver of MPUC rules in order to allow Gas Operations to recover approximately $21 million in unrecovered purchased gas costs related to periods prior to July 1, 2004. Those unrecovered gas costs were identified as a result of revisions to previously approved calculations of unrecovered purchased gas costs. Following that denial, Gas Operations recorded a $21 million adjustment to reduce pre-tax earnings in the fourth quarter of 2006 and reduced the regulatory asset related to these costs by an equal amount. In March 2007, following the MPUC’s denial of reconsideration of its ruling, Gas Operations petitioned the Minnesota Court of Appeals for review of the MPUC’s decision. That court heard oral arguments on the appeal in February 2008 and is expected to render its decision within 90 days of that hearing. No prediction can be made as to the ultimate outcome of this matter.

(5) Derivative Instruments

     The Company is exposed to various market risks. These risks arise from transactions entered into in the normal course of business. The Company utilizes derivative instruments such as physical forward contracts, swaps and options to mitigate the impact of changes in commodity prices, weather and interest rates on its operating results and cash flows.

 (a)  Non-Trading Activities

     Cash Flow Hedges.  The Company has entered into certain derivative instruments that qualify as cash flow hedges under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS No. 133). The objective of these derivative instruments is to hedge the price risk associated with natural gas purchases and sales to reduce cash flow variability related to meeting the Company’s wholesale and retail customer obligations. During each of the three months ended March 31, 2007 and 2008, hedge ineffectiveness resulted in a loss of less than $1 million from derivatives that qualify for and are designated as cash flow hedges. No component of the derivative instruments’ gain or loss was excluded from the assessment of effectiveness. If it becomes probable that an anticipated transaction being hedged will not occur, the Company realizes in net income the deferred gains and losses previously recognized in accumulated other comprehensive loss. When an anticipated transaction being hedged affects earnings, the accumulated deferred gain or loss recognized in accumulated other comprehensive loss is reclassified and included in the Statements of Consolidated Income under the “Expenses” caption “Natural gas.” Cash flows resulting from these transactions in non-trading energy derivatives are included in the Statements of Consolidated Cash Flows in the same category as the item being hedged. As of March 31, 2008, the Company expects $2 million ($1 million after-tax) in accumulated other comprehensive income to be reclassified as a decrease in Natural gas expense during the next twelve months.

     The length of time the Company is hedging its exposure to the variability in future cash flows using derivative instruments that have been designated and have qualified as cash flow hedging instruments is less than one year. The Company’s policy is not to exceed ten years in hedging its exposure.

     Hedging of Future Debt Issuances. As of March 31, 2008, the Company had outstanding treasury rate lock derivative instruments (treasury rate locks) with an aggregate notional amount of $300 million, expiration dates of June 2008 and a weighted-average locked U.S. treasury rate on ten-year debt of 4.05%. These treasury rate locks were executed to hedge the ten-year U.S. treasury rate expected to be used in pricing the forecasted issuance of $300 million of fixed-rate debt in 2008, as changes in the U.S treasury rate would cause variability in the Company’s forecasted interest payments. These treasury rate locks qualify as cash flow hedges under SFAS No. 133. Accordingly, unrealized gains and losses associated with the treasury rate locks are recorded as a component of accumulated other comprehensive loss. The realized gain or loss recognized upon settlement of the treasury rate locks will be initially recorded as a component of accumulated other comprehensive loss and will be recognized as a component of interest expense over the life of the related financing arrangement. During the three months ended March 31, 2008, the Company recognized a $14 million loss ($9 million after-tax) for these treasury rate locks in other comprehensive loss. Ineffectiveness for the treasury rate locks was not material during the three months ended March 31, 2008.

     Other Derivative Instruments.  The Company enters into certain derivative instruments to manage physical commodity price risks that do not qualify or are not designated as cash flow or fair value hedges under SFAS No. 133. The Company utilizes these financial instruments to manage physical commodity price risks and does not engage in proprietary or speculative commodity trading. During the three months ended March 31, 2007 and 2008, the Company recognized unrealized net losses of $8 million and $22 million, respectively. During the three months ended March 31, 2007, the unrealized net losses are included in the Statements of Consolidated Income under the “Expenses” caption “Natural Gas.” During the three months ended March 31, 2008, unrealized net losses of $20 million are included in the Statements of Consolidated Income under the “Revenues” caption and unrealized net losses of $2 million are included in the Statements of Consolidated Income under the “Expenses” caption “Natural Gas.”

     Weather Derivatives. The Company has weather normalization or other rate mechanisms that mitigate the impact of weather in certain of its Gas Operations jurisdictions. The remaining Gas Operations jurisdictions,

Minnesota, Mississippi and Texas, do not have such mechanisms. As a result, fluctuations from normal weather may have a significant positive or negative effect on the results of these operations.

     In 2007, the Company entered into heating-degree day swaps to mitigate the effect of fluctuations from normal weather on its financial position and cash flows for the 2007/2008 winter heating season. The swaps are based on ten-year normal weather and provide for a maximum payment by either party of $18 million. During the three months ended March 31, 2008, the Company recognized an $11 million loss ($7 million after-tax) related to these swaps. This was offset in part by increased revenues due to colder than normal weather.

     Embedded Derivative.  The Company’s 3.75% convertible senior notes contain contingent interest provisions. The contingent interest component is an embedded derivative as defined by SFAS No. 133, and accordingly, must be split from the host instrument and recorded at fair value on the balance sheet. The value of the contingent interest component was not material at issuance or at March 31, 2008.

(6) Goodwill

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

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

(7) Comprehensive Income

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

		For the Three Months Ended
		March 31,
		2007				2008
		(in millions)
Net income		$	130			$	123
Other comprehensive income (loss):
SFAS No. 158 adjustment (net of tax of $1 and $1)			2				2
Net deferred loss from cash flow hedges (net of tax of $5)			—				(9	)
Reclassification of deferred gain from cash flow hedges realized in net income (net of tax of $14 and $2)			(22	)			(4	)
Other comprehensive loss			(20	)			(11	)
Comprehensive income		$	110			$	112

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

		December 31,				March 31,
		2007				2008
		(in millions)
SFAS No. 158 adjustment		$	(48	)		$	(46	)
Net deferred gain (loss) from cash flow hedges			4				(9	)
Total accumulated other comprehensive loss		$	(44	)		$	(55	)

(8) Capital Stock

     CenterPoint Energy has 1,020,000,000 authorized shares of capital stock, comprised of 1,000,000,000 shares of $0.01 par value common stock and 20,000,000 shares of $0.01 par value preferred stock. At December 31, 2007, 322,718,951 shares of CenterPoint Energy common stock were issued and 322,718,785 shares of CenterPoint Energy common stock were outstanding. At March 31, 2008, 328,265,242 shares of CenterPoint Energy common

stock were issued and 328,265,076 shares of CenterPoint Energy common stock were outstanding. See Note 9(b) describing the conversion of the 3.75% Convertible Senior Notes in the first quarter of 2008. Outstanding common shares exclude 166 treasury shares at both December 31, 2007 and March 31, 2008.

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

(a) Short-term Borrowings

     In October 2007, CERC amended its receivables facility and extended the termination date to October 28, 2008. The facility size will range from $150 million to $375 million during the period from September 30, 2007 to the October 28, 2008 termination date. The variable size of the facility was designed to track the seasonal pattern of receivables in CERC’s natural gas businesses. At March 31, 2008, the facility size was $375 million. As of December 31, 2007 and March 31, 2008, $232 million and $200 million, respectively, was advanced for the purchase of receivables under CERC’s receivables facility.

(b) Long-term Debt

     Revolving Credit Facilities. As of March 31, 2008, the Company had no borrowings, approximately $28 million of outstanding letters of credit and no commercial paper outstanding under its $1.2 billion credit facility. As of March 31, 2008, CenterPoint Houston had no borrowings and approximately $4 million of outstanding letters of credit under its $300 million credit facility and CERC Corp. had $100 million of borrowings and $35 million of commercial paper outstanding under its $950 million credit facility. The Company, CenterPoint Houston and CERC Corp. were in compliance with all debt covenants as of March 31, 2008.

     Transition Bonds.  Pursuant to a financing order issued by the Texas Utility Commission in September 2007, in February 2008 a subsidiary of CenterPoint Houston issued approximately $488 million in transition bonds in two tranches with interest rates of 4.192% and 5.234% and final maturity dates of February 2020 and February 2023, respectively. Scheduled final payment dates are February 2017 and February 2020. Through issuance of the transition bonds, CenterPoint Houston securitized transition property of approximately $483 million representing the remaining balance of the CTC adjusted to refund certain unspent environmental retrofit costs and to recover the amount of the fuel reconciliation settlement. See Note 4(a) for further discussion.

     Convertible Debt.  On May 19, 2003, the Company issued $575 million aggregate principal amount of convertible senior notes due May 15, 2023 with an interest rate of 3.75%. As of March 31, 2008, holders could convert each of their notes into shares of CenterPoint Energy common stock at a conversion rate of 89.4381 shares of common stock per $1,000 principal amount of notes at any time prior to maturity under the following circumstances: (1) if the last reported sale price of CenterPoint Energy common stock for at least 20 trading days during the period of 30 consecutive trading days ending on the last trading day of the previous calendar quarter is greater than or equal to 120% or, following May 15, 2008, 110% of the conversion price per share of CenterPoint Energy common stock on such last trading day, (2) if the notes have been called for redemption, (3) during any period in which the credit ratings assigned to the notes by both Moody’s Investors Service, Inc. (Moody’s) and Standard & Poor’s Ratings Services (S&P), a division of The McGraw-Hill Companies, are lower than Ba2 and BB, respectively, or the notes are no longer rated by at least one of these ratings services or their successors, or (4) upon the occurrence of specified corporate transactions, including the distribution to all holders of CenterPoint Energy common stock of certain rights entitling them to purchase shares of CenterPoint Energy common stock at less than the last reported sale price of a share of CenterPoint Energy common stock on the trading day prior to the declaration date of the distribution or the distribution to all holders of CenterPoint Energy common stock of the Company’s assets, debt securities or certain rights to purchase the Company’s securities, which distribution has a per share value exceeding 15% of the last reported sale price of a share of CenterPoint Energy common stock on the trading day immediately preceding the declaration date for such distribution. The notes originally had a conversion rate of 86.3558 shares of common stock per $1,000 principal amount of notes. However, the conversion rate increased to 89.4381 shares at March 31, 2008, in accordance with the terms of the notes, because quarterly common stock dividends declared were in excess of $0.10 per share.

     Holders have the right to require the Company to purchase all or any portion of the notes for cash on May 15, 2008, May 15, 2013 and May 15, 2018 for a purchase price equal to 100% of the principal amount of the notes. The convertible senior notes also have a contingent interest feature requiring contingent interest to be paid to holders of

notes commencing on or after May 15, 2008, in the event that the average trading price of a note for the applicable five-trading-day period equals or exceeds 120% of the principal amount of the note as of the day immediately preceding the first day of the applicable six-month interest period. For any six-month period, contingent interest will be equal to 0.25% of the average trading price of the note for the applicable five-trading-day period.

     In August 2005, the Company accepted for exchange approximately $572 million aggregate principal amount of its 3.75% convertible senior notes due 2023 (Old Notes) for an equal amount of its new 3.75% convertible senior notes due 2023 (New Notes). As of March 31, 2008, New Notes of approximately $401 million remained outstanding and Old Notes of approximately $1 million remained outstanding. Under the terms of the New Notes, which are substantially similar to the Old Notes, settlement of the principal portion will be made in cash rather than stock.

     During the three months ended March 31, 2008, the Company issued 4.4 million shares of its common stock and paid cash of approximately $131 million to settle conversions of approximately $133 million principal amount of its 3.75% convertible senior notes. In April 2008, the Company issued 0.25 million shares of its common stock and paid cash of approximately $11 million to settle a conversion of approximately $11 million principal amount of its convertible notes.

     As of December 31, 2007 and March 31, 2008, the 3.75% convertible senior notes are included as current portion of long-term debt in the Consolidated Balance Sheets because the last reported sale price of CenterPoint Energy common stock for at least 20 trading days during the period of 30 consecutive trading days ending on the last trading day of the quarter was greater than or equal to 120% of the conversion price of the 3.75% convertible senior notes and therefore, the 3.75% convertible senior notes meet the criteria that make them eligible for conversion at the option of the holders of these notes.

     In April 2008, the Company announced a call for redemption of its 3.75% convertible senior notes, at 100% of their principal amount, on May 30, 2008. Substantially all of such notes are expected to be converted by holders prior to the redemption date, and substantially all of such conversions are expected to be settled with a cash payment for the principal amount and delivery of shares of the Company’s common stock for the excess value due converting holders. If the Company’s closing stock price of $15.57 at April 25, 2008 were unchanged at the dates of the conversions, assuming the conversion of approximately $391 million aggregate principal amount of the notes at the current conversion rate, common stock reflecting a conversion premium of $153 million would be issued to the converting holders.  The conversion rate will be increased as a result of the Company’s April 24, 2008 declaration of a regular quarterly cash dividend of $0.1825 per share.  Under the terms of the indenture governing the notes, the increased conversion rate will be determined on May 13, 2008.

     Purchase of Pollution Control Bonds. In April 2008, the Company purchased $175 million principal amount of pollution control bonds issued on its behalf at 102% of their principal amount. Prior to the purchase, $100 million principal amount of such bonds had a fixed rate of interest of 7.75% and $75 million principal amount of such bonds had a fixed rate of interest of 8%. Depending on market conditions, the Company expects to remarket both series of bonds, at 100% of their principal amounts, in 2008.

(10) Commitments and Contingencies

(a) Natural Gas Supply Commitments

     Natural gas supply commitments include natural gas contracts related to the Company’s Natural Gas Distribution and Competitive Natural Gas Sales and Services business segments, which have various quantity requirements and durations, that are not classified as non-trading derivative assets and liabilities in the Company’s Consolidated Balance Sheets as of December 31, 2007 and March 31, 2008 as these contracts meet the SFAS No. 133 exception to be classified as “normal purchases contracts” or do not meet the definition of a derivative. Natural gas supply commitments also include natural gas transportation contracts which do not meet the definition of a derivative. As of March 31, 2008, minimum payment obligations for natural gas supply commitments are approximately $532 million for the remaining nine months in 2008, $316 million in 2009, $296 million in 2010, $279 million in 2011, $272 million in 2012 and $1.2 billion after 2012.

(b) Legal, Environmental and Other Regulatory Matters

Legal Matters

RRI Indemnified Litigation

     The Company, CenterPoint Houston or their 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 the Company and Reliant Energy, Inc. (formerly Reliant Resources, Inc.) (RRI), the Company and its subsidiaries are entitled to be indemnified by RRI for any losses, including attorneys’ fees and other costs, arising out of the lawsuits described below under “Electricity and Gas Market Manipulation Cases” and “Other Class Action Lawsuits.” Pursuant to the indemnification obligation, RRI is defending the Company and its subsidiaries to the extent named in these lawsuits. Although the ultimate outcome of these matters cannot be predicted at this time, the Company has not considered it necessary to establish reserves related to this litigation.

     Electricity and Gas Market Manipulation Cases. A large number of lawsuits have been filed against numerous market participants and remain pending in federal court in Nevada and in state court in California, Missouri and Nevada in connection with the operation of the electricity and natural gas markets in California and certain other states in 2000-2001, a time of power shortages and significant increases in prices. These lawsuits, many of which have been filed as class actions, are based on a number of legal theories, including violation of state and federal antitrust laws, laws against unfair and unlawful business practices, the federal Racketeer Influenced Corrupt Organization Act, false claims statutes and similar theories and breaches of contracts to supply power to governmental entities. Plaintiffs in these lawsuits, which include state officials and governmental entities as well as private litigants, are seeking a variety of forms of relief, including recovery of compensatory damages (in some cases in excess of $1 billion), a trebling of compensatory damages and punitive damages, injunctive relief, restitution, interest due, disgorgement, civil penalties and fines, costs of suit and attorneys’ fees. The Company’s former subsidiary, RRI, was a participant in the California markets, owning generating plants in the state and participating in both electricity and natural gas trading in that state and in western power markets generally.

     The Company and/or Reliant Energy have been named in approximately 35 of these lawsuits, which were instituted between 2001 and 2007 and are pending in Nevada state court in Clark County, in Missouri state court in Jackson County and in federal district court in Nevada. However, the Company, CenterPoint Houston and Reliant Energy were not participants in the electricity or natural gas markets in California. The Company and Reliant Energy have been dismissed from certain of the lawsuits, either voluntarily by the plaintiffs or by order of the court, and the Company believes it is not a proper defendant in the remaining cases and will continue to seek dismissal from such remaining cases.

     To date, several of the electricity complaints have been dismissed, and several of the dismissals have been affirmed by appellate courts. Others have been resolved by the settlement described in the following paragraph. Three of the gas complaints were dismissed based on defendants’ claims of the filed rate doctrine, but the Ninth Circuit Court of Appeals reversed those dismissals and remanded the cases back to the district court for further proceedings. In June 2005, a San Diego state court refused to dismiss other gas complaints on the same basis. In October 2006, RRI reached a tentative settlement of 11 class action natural gas cases pending in state court in California. The court approved this settlement in June 2007. In the remaining gas cases in state court in California, the Court of Appeals found that the Company was not a successor to the liabilities of a subsidiary of RRI and ordered the state court to dismiss the Company. The Company was dismissed in April 2008. The other gas cases remain in the early procedural stages.

     In August 2005, RRI reached a settlement with the Federal Energy Regulatory Commission (FERC) enforcement staff, the states of California, Washington and Oregon, California’s three largest investor-owned utilities, classes of consumers from California and other western states, and a number of California city and county government entities that resolves their claims against RRI related to the operation of the electricity markets in California and certain other western states in 2000-2001. The settlement also resolves the claims of the three states and the investor-owned utilities related to the 2000-2001 natural gas markets. The settlement has been approved by the FERC, by the California Public Utilities Commission and by the courts in which the electricity class action cases are pending. Two parties have appealed the courts’ approval of the settlement to the California Court of Appeals. A

party in the FERC proceedings filed a motion for rehearing of the FERC’s order approving the settlement, which the FERC denied in May 2006. That party has filed for review of the FERC’s orders in the Ninth Circuit Court of Appeals. The Company is not a party to the settlement, but may rely on the settlement as a defense to any claims brought against it related to the time when the Company was an affiliate of RRI. The terms of the settlement do not require payment by the Company.

     Other Class Action Lawsuits. In May 2002, three class action lawsuits were filed in federal district court in Houston on behalf of participants in various employee benefits plans sponsored by the Company. Two of the lawsuits were dismissed without prejudice. In the remaining lawsuit, the Company and certain former members of its benefits committee are defendants. That lawsuit alleged that the defendants breached their fiduciary duties to various employee benefits plans, directly or indirectly sponsored by the Company, in violation of the Employee Retirement Income Security Act of 1974 by permitting the plans to purchase or hold securities issued by the Company when it was imprudent to do so, including after the prices for such securities became artificially inflated because of alleged securities fraud engaged in by the defendants. The complaint sought monetary damages for losses suffered on behalf of the plans and a putative class of plan participants whose accounts held CenterPoint Energy or RRI securities, as well as restitution. In January 2006, the federal district judge granted a motion for summary judgment filed by the Company and the individual defendants. The plaintiffs appealed the ruling to the Fifth Circuit Court of Appeals (Fifth Circuit), which in April 2008 affirmed the district court’s ruling. The plaintiffs could seek rehearing of that decision by Fifth Circuit and, if that is unsuccessful, further review by the United States Supreme Court. The Company believes that this lawsuit is without merit and will continue to vigorously defend the case. However, the ultimate outcome of this matter cannot be predicted at this time.

Other Legal Matters

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

     In addition, CERC Corp. and certain of its subsidiaries are defendants in two mismeasurement lawsuits brought against approximately 245 pipeline companies and their affiliates pending in state court in Stevens County, Kansas. In one case (originally filed in May 1999 and amended four times), the plaintiffs purport to represent a class of royalty owners who allege that the defendants have engaged in systematic mismeasurement of the volume of natural gas for more than 25 years. The plaintiffs amended their petition in this suit in July 2003 in response to an order from the judge denying certification of the plaintiffs’ alleged class. In the amendment the plaintiffs dismissed their claims against certain defendants (including two CERC Corp. subsidiaries), limited the scope of the class of plaintiffs they purport to represent and eliminated previously asserted claims based on mismeasurement of the British thermal unit (Btu) content of the gas. The same plaintiffs then filed a second lawsuit, again as representatives of a putative class of royalty owners, in which they assert their claims that the defendants have engaged in systematic mismeasurement of the Btu content of natural gas for more than 25 years. In both lawsuits, the plaintiffs seek compensatory damages, along with statutory penalties, treble damages, interest, costs and fees. CERC believes that there has been no systematic mismeasurement of gas and that the lawsuits are without merit. CERC does 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 the Company or CERC.

     Gas Cost Recovery Litigation. In October 2002, a lawsuit was filed on behalf of certain CERC ratepayers in state district court in Wharton County, Texas against the Company, CERC, Entex Gas Marketing Company (EGMC), and certain non-affiliated companies alleging fraud, violations of the Texas Deceptive Trade Practices Act, violations of the Texas Utilities Code, civil conspiracy and violations of the Texas Free Enterprise and Antitrust Act with respect to rates charged to certain consumers of natural gas in the State of Texas. The plaintiffs initially sought certification of a class of Texas ratepayers, but subsequently dropped their request for class certification. The

plaintiffs later added as defendants CenterPoint Energy Marketing Inc., CenterPoint Energy Pipeline Services, Inc. (CEPS), and certain other subsidiaries of CERC, and other non-affiliated companies. In February 2005, the case was removed to federal district court in Houston, Texas, and in March 2005, the plaintiffs voluntarily dismissed the case and agreed not to refile the claims asserted unless the Miller County case described below is not certified as a class action or is later decertified.

     In October 2004, a lawsuit was filed by certain CERC ratepayers in Texas and Arkansas in circuit court in Miller County, Arkansas against the Company, CERC, EGMC, CenterPoint Energy Gas Transmission Company (CEGT), CenterPoint Energy Field Services (CEFS), CEPS, Mississippi River Transmission Corp. (MRT) and other non-affiliated companies alleging fraud, unjust enrichment and civil conspiracy with respect to rates charged to certain consumers of natural gas in Arkansas, Louisiana, Minnesota, Mississippi, Oklahoma and Texas. Subsequently, the plaintiffs dropped CEGT and MRT as defendants. Although the plaintiffs in the Miller County case sought class certification, no class was certified. In June 2007, the Arkansas Supreme Court determined that the Arkansas claims were within the sole and exclusive jurisdiction of the Arkansas Public Service Commission (APSC). In response to that ruling, in August 2007 the Miller County court stayed but refused to dismiss the Arkansas claims. In February 2008, the Arkansas Supreme Court directed the Miller County court to dismiss the entire case for lack of jurisdiction. The Miller County court subsequently dismissed the case in accordance with the Arkansas Supreme Court’s mandate and all appellate deadlines have expired.

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

     In August 2007, the Arkansas plaintiff in the Miller County litigation initiated a complaint at the APSC seeking a decision concerning the extent of the APSC’s jurisdiction over the Miller County case and an investigation into the merits of the allegations asserted in his complaint with respect to CERC. That complaint remains pending at the APSC.

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

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

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

The court ruled that the plaintiffs own native gas underlying those lands, since neither CEGT nor its predecessors had condemned those ownership interests. The court rejected CEGT’s contention that the claim should be barred by the statute of limitations, since the suit was filed over 25 years after the facility was constructed. The court also rejected CEGT’s contention that the suit is an impermissible attack on the determinations the FERC and Oklahoma Corporation Commission made regarding the absence of native gas in the lands when the facility was constructed. The summary judgment ruling was only on the issue of liability, though the court did rule that CEGT has the burden of proving that any gas in the Wapanucka formation is gas that has been injected and is not native gas. Further hearings and orders of the court are required to specify the appropriate relief for the plaintiffs. CEGT plans to appeal through the Oklahoma court system any judgment that imposes liability on CEGT in this matter. The Company and CERC do not expect the outcome of this matter to have a material impact on the financial condition, results of operations or cash flows of either the Company or CERC.

  Environmental Matters

     Manufactured Gas Plant Sites. CERC and its predecessors operated manufactured gas plants (MGP) 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, 2008, 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. As of March 31, 2008, CERC had collected $13 million from insurance companies and rate payers to be used for future environmental remediation.

     In addition to the Minnesota sites, the United States Environmental Protection Agency and other regulators have investigated MGP sites that were owned or operated by 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 is required to determine if other potentially responsible parties, including CERC, would have to contribute to that remediation. The Company is investigating details regarding the site and the range of environmental expenditures for potential remediation. However, 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.

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

     Asbestos. Some facilities owned by the Company contain or have contained asbestos insulation and other asbestos-containing materials. The Company or its subsidiaries have been named, along with numerous others, as a defendant in lawsuits filed by a number of individuals who claim injury due to exposure to asbestos. Some of the claimants have worked at locations owned by the Company, but most existing claims relate to facilities previously owned by the Company or its subsidiaries. The Company anticipates that additional claims like those received may

be asserted in the future. In 2004, the Company sold its generating business, to which most of these claims relate, to Texas Genco LLC, which is now known as NRG Texas LP (NRG). Under the terms of the arrangements regarding separation of the generating business from the Company and its sale to Texas Genco LLC, ultimate financial responsibility for uninsured losses from claims relating to the generating business has been assumed by Texas Genco LLC and its successor, but the Company has agreed to continue to defend such claims to the extent they are covered by insurance maintained by the Company, subject to reimbursement of the costs of such defense from the purchaser. Although their ultimate outcome cannot be predicted at this time, the Company intends to continue vigorously contesting claims that it does not consider to have merit and does not expect, based on its experience to date, these matters, either individually or in the aggregate, to have a material adverse effect on the Company’s financial condition, results of operations or cash flows.

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

  Other Proceedings

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

  Guaranties

     Prior to the Company’s distribution of its ownership in RRI to its shareholders, CERC had guaranteed certain contractual obligations of what became RRI’s trading subsidiary. Under the terms of the separation agreement between the companies, RRI agreed to extinguish all such guaranty obligations prior to separation, but at the time of separation in September 2002, RRI had been unable to extinguish all obligations. To secure CERC against obligations under the remaining guaranties, RRI agreed to provide cash or letters of credit for CERC’s benefit, and undertook to use commercially reasonable efforts to extinguish the remaining guaranties. In December 2007, the Company, CERC and RRI amended that agreement and CERC released the letters of credit it held as security. Under the revised agreement RRI agreed to provide cash or new letters of credit to secure CERC against exposure under the remaining guaranties as calculated under the new agreement if and to the extent changes in market conditions exposed CERC to a risk of loss on those guaranties.

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

(11) Income Taxes

     During the three months ended March 31, 2007 and 2008, the effective tax rate was 36% and 37%, respectively.  The most significant item affecting the comparability of the effective tax rate is the 2008 classification of approximately $4 million of Texas margin tax as an income tax for CenterPoint Houston.

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

		December 31,				March 31,
		2007				2008
Liability for uncertain tax positions		$	82			$	89
Portion of liability for uncertain tax positions that, if recognized, would reduce the effective income tax rate			10				11
Interest accrued on uncertain tax positions			4				5

(12) Earnings Per Share

     The following table reconciles numerators and denominators of the Company’s basic and diluted earnings per share calculations:

		Three Months Ended March 31,
		2007				2008
		(in millions, except share and
		per share amounts)
Basic earnings per share calculation:
Net income		$	130			$	123
Weighted average shares outstanding			318,060,000				327,279,000
Basic earnings per share:
Net income		$	0.41			$	0.38
Diluted earnings per share calculation:
Net income		$	130			$	123
Weighted average shares outstanding			318,060,000				327,279,000
Plus: Incremental shares from assumed conversions:
Stock options (1)			1,237,000				869,000
Restricted stock			1,328,000				1,127,000
2.875% convertible senior notes			1,179,000				—
3.75% convertible senior notes			18,299,000				10,173,000
Weighted average shares assuming dilution			340,103,000				339,448,000
Diluted earnings per share:
Net income		$	0.38			$	0.36

     Substantially all of the 3.75% contingently convertible senior notes provide for settlement of the principal portion in cash rather than stock. In accordance with EITF Issue No. 04-8, “Accounting Issues related to Certain Features of Contingently Convertible Debt and the Effect on Diluted Earnings Per Share,” the portion of the conversion value of such notes that must be settled in cash rather than stock is excluded from the computation of diluted earnings per share from continuing operations. The Company includes the conversion spread in the calculation of diluted earnings per share when the average market price of the Company’s common stock in the respective reporting period exceeds the conversion price. The conversion price for the 3.75% contingently convertible senior notes at March 31, 2008 was $11.18.

(13) Reportable Business Segments

     The Company’s determination of reportable business segments considers the strategic operating units under which the Company manages sales, allocates resources and assesses performance of various products and services to

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

     The Company’s reportable business segments include the following: Electric Transmission & Distribution, Natural Gas Distribution, Competitive Natural Gas Sales and Services, Interstate Pipelines, Field Services and Other Operations. The electric transmission and distribution function (CenterPoint Houston) is reported in the Electric Transmission & Distribution business segment. Natural Gas Distribution consists of intrastate natural gas sales to, and natural gas transportation and distribution for, residential, commercial, industrial and institutional customers. Competitive Natural Gas Sales and Services represents the Company’s non-rate regulated gas sales and services operations, which consist of three operational functions: wholesale, retail and intrastate pipelines. The Interstate Pipelines business segment includes the interstate natural gas pipeline operations. The Field Services business segment includes the natural gas gathering operations. Other Operations consists primarily of other corporate operations which support all of the Company’s business operations.

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

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

		For the Three Months Ended March 31, 2007
		Revenues from				Net								Total Assets
		External				Intersegment				Operating				as of December 31,
		Customers				Revenues				Income (Loss)				2007
Electric Transmission & Distribution		$	406	(1)		$	—			$	104			$	8,358
Natural Gas Distribution			1,564				3				129				4,332
Competitive Natural Gas Sales and Services			1,047				17				56				1,221
Interstate Pipelines			59				31				44				3,007
Field Services			28				11				22				669
Other Operations			2				—				(2	)			1,956	(2)
Eliminations			—				(62	)			—				(1,671	)
Consolidated		$	3,106			$	—			$	353			$	17,872

		For the Three Months Ended March 31, 2008
		Revenues from				Net								Total Assets
		External				Intersegment				Operating				as of March 31,
		Customers				Revenues				Income (Loss)				2008
Electric Transmission & Distribution		$	409	(1)		$	—			$	91			$	8,221
Natural Gas Distribution			1,697				3				121				4,171
Competitive Natural Gas Sales and Services			1,109				11				6				1,316
Interstate Pipelines			91				42				71				3,087
Field Services			54				4				45				724
Other Operations			3				—				2				2,050	(2)
Eliminations			—				(60	)			—				(2,034	)
Consolidated		$	3,363			$	—			$	336			$	17,535

(14) Subsequent Event

     On April 24, 2008, the Company’s board of directors declared a regular quarterly cash dividend of $0.1825 per share of common stock payable on June 10, 2008, to shareholders of record as of the close of business on May 16, 2008.

     Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS OF CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

     The following discussion and analysis should be read in combination with our Interim Condensed Financial Statements contained in this Form 10-Q and our Annual Report on Form 10-K for the year ended December 31, 2007 (2007 Form 10-K).

EXECUTIVE SUMMARY

Recent Events

Debt Financing Transactions

     In April 2008, we purchased $175 million principal amount of pollution control bonds issued on our behalf at 102% of their principal amount. Prior to the purchase, $100 million principal amount of such bonds had a fixed rate of interest of 7.75% and $75 million principal amount of such bonds had a fixed rate of interest of 8%. Depending on market conditions, we expect to remarket both series of bonds, at 100% of their principal amounts, in 2008.

     During the three months ended March 31, 2008, we issued 4.4 million shares of our common stock and paid cash of approximately $131 million to settle conversions of approximately $133 million principal amount of our 3.75% convertible senior notes. Convertible senior notes aggregating $402 million remained outstanding at March 31, 2008. In April 2008, we issued 0.25 million shares of our common stock and paid cash of approximately $11 million to settle a conversion of approximately $11 million principal amount of our 3.75% convertible notes.

     In April 2008, we announced a call for redemption of our 3.75% convertible senior notes, at 100% of their principal amount, on May 30, 2008. Substantially all of such notes are expected to be converted by holders prior to the redemption date, and substantially all of such conversions are expected to be settled with a cash payment for the principal amount and delivery of shares of our common stock for the excess value due converting holders. If our closing stock price of $15.57 at April 25, 2008 were unchanged at the dates of the conversions, assuming the conversion of approximately $391 million aggregate principal amount of the notes at the current conversion rate, common stock reflecting a conversion premium of $153 million would be issued to the converting holders.  The conversion rate will be increased as a result of our April 24, 2008 declaration of a regular quarterly cash dividend of $0.1825 per share.  Under the terms of the indenture governing the notes, the increased conversion rate will be determined on May 13, 2008.

Transition Bonds

     Pursuant to a financing order issued by the Public Utility Commission of Texas (Texas Utility Commission) in September 2007, in February 2008 a subsidiary of CenterPoint Energy Houston Electric, LLC (CenterPoint Houston) issued approximately $488 million in transition bonds in two tranches with interest rates of 4.192% and 5.234% and final maturity dates in February 2020 and February 2023, respectively. Scheduled final payment dates are February 2017 and February 2020. Through issuance of the transition bonds, CenterPoint Houston securitized transition property of approximately $483 million representing the remaining balance of the competition transition charge (CTC) adjusted to refund certain unspent environmental retrofit costs and to recover the amount of the fuel reconciliation settlement.

Interstate Pipelines

     In May 2007, CenterPoint Energy Gas Transmission (CEGT), a wholly owned subsidiary of CERC Corp., received Federal Energy Regulatory Commission (FERC) approval for the third phase of its Carthage to Perryville pipeline project, a 172-mile, 42-inch diameter pipeline and related compression facilities for the transportation of gas from Carthage, Texas to CEGT’s Perryville hub in northeast Louisiana, to expand capacity of the pipeline to 1.5 Bcf per day by adding additional compression and operating at higher pressures. In July 2007, CEGT received approval from the Pipeline and Hazardous Materials Administration (PHMSA) to increase the maximum allowable operating pressure.  The PHMSA’s approval contained certain conditions and requirements. In March 2008, CEGT met these conditions and gave notice to PHMSA that it would be increasing the pressure in 30 days. In April 2008, CEGT raised the maximum allowable pressure and concurrently placed the phase three expansion in-service. CEGT has executed contracts for approximately 150 MMcf per day of the 250 MMcf per day phase three expansion. 

     In September 2007, CEGT initiated an investigation into allegations received from two former employees of the manufacturer of pipe installed in CEGT’s Carthage to Perryville pipeline segment. That pipeline segment was placed in commercial service in May 2007 after satisfactory completion of hydrostatic testing designed to ensure that the pipe and its welds would be structurally sound when placed in service and operated at design pressure. According to the complainants, records relating to radiographic inspections of certain welds made at the fabrication facility had been altered resulting in the possibility that pipe with alleged substandard welds had been installed in the pipeline. In conducting its investigation, among other things, CEGT and its counsel interviewed the complainants and other individuals, including CEGT and contractor personnel, and reviewed documentation related to the manufacture and construction of the pipeline, including radiographic records related to the allegedly deficient welds. CEGT kept appropriate governmental officials informed throughout its investigation and consulted appropriate technical consultants and pre-existing regulatory guidance.  Pursuant to a course of action proposed by CEGT, CEGT excavated and inspected certain welds, and in each case, CEGT found those welds to be structurally sound. CEGT and its counsel have now  formally concluded their investigation, finding no  credible support for the allegation that pipe with substandard welds  may have been installed in the pipeline.  CEGT has informed the relevant government agencies of these conclusions, and has informed those agencies that CEGT does not intend to take any additional action or to alter or modify the pipeline’s operations.

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

CONSOLIDATED RESULTS OF OPERATIONS

     All dollar amounts in the tables that follow are in millions, except for per share amounts.

		Three Months Ended March 31,
		2007				2008
Revenues		$	3,106			$	3,363
Expenses			2,753				3,027
Operating Income			353				336
Interest and Other Finance Charges			(123	)			(115	)
Interest on Transition Bonds			(31	)			(33	)
Other Income, net			3				9
Income Before Income Taxes			202				197
Income Tax Expense			(72	)			(74	)
Net Income		$	130			$	123
Basic Earnings Per Share		$	0.41			$	0.38
Diluted Earnings Per Share		$	0.38			$	0.36

Three months ended March 31, 2008 compared to three months ended March 31, 2007

     We reported consolidated net income of $123 million ($0.36 per diluted share) for the three months ended March 31, 2008 as compared to $130 million ($0.38 per diluted share) for the same period in 2007. The decrease in net income of $7 million was primarily due to decreased operating income of $50 million in our Competitive Natural Gas Sales and Services business segment, decreased operating income of $14 million in our Electric Transmission & Distribution utility and decreased operating income of $8 million in our Natural Gas Distribution business segment. These decreases in consolidated net income were partially offset by increased operating income of $27 million in our Interstate Pipelines business segment, increased operating income of $23 million in our Field Services business segment, decreased interest expense, excluding interest on transition bonds, of $8 million due to lower amortization of deferred financing costs and increased operating income of $4 million in our Other Operations business segment.

     During the three months ended March 31, 2008 and 2007, the effective tax rate was 37% and 36%, respectively.  The most significant item affecting the comparability of the effective tax rate is the 2008 classification of approximately $4 million of Texas margin tax as an income tax for CenterPoint Houston.

RESULTS OF OPERATIONS BY BUSINESS SEGMENT

     The following table presents operating income (in millions) for each of our business segments for the three months ended March 31, 2007 and 2008.

		Three Months Ended March 31,
		2007				2008
Electric Transmission & Distribution		$	104			$	91
Natural Gas Distribution			129				121
Competitive Natural Gas Sales and Services			56				6
Interstate Pipelines			44				71
Field Services			22				45
Other Operations			(2	)			2
Total Consolidated Operating Income		$	353			$	336

Electric Transmission & Distribution

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

     The following tables provide summary data of our Electric Transmission & Distribution business segment for the three months ended March 31, 2007 and 2008 (in millions, except throughput and customer data):

		Three Months Ended March 31,
		2007				2008
Revenues:
Electric transmission and distribution utility		$	347			$	346
Transition bond companies			59				63
Total revenues			406				409
Expenses:
Operation and maintenance, excluding transition bond companies			154				168
Depreciation and amortization, excluding transition bond companies			63				66
Taxes other than income taxes			57				53
Transition bond companies			28				31
Total expenses			302				318
Operating Income		$	104			$	91
Operating Income:
Electric transmission and distribution utility			62				54
Competition transition charge			11				5
Transition bond companies (1)			31				32
Total segment operating income		$	104			$	91
Throughput (in gigawatt-hours (GWh)):
Residential			4,658				4,403
Total			16,660				16,570
Average number of metered customers:
Residential			1,752,264				1,801,272
Total			1,989,744				2,042,460

Three months ended March 31, 2008 compared to three months ended March 31, 2007

     Our Electric Transmission & Distribution business segment reported operating income of $91 million for the three months ended March 31, 2008, consisting of $54 million for the regulated electric transmission and distribution utility (TDU), $5 million for the CTC and $32 million related to the transition bonds. For the three months ended March 31, 2007, operating income totaled $104 million, consisting of $62 million for the TDU, $11 million for the CTC and $31 million related to the transition bonds. The reduction in operating income from the TDU resulted from reduced usage ($11 million), in part due to milder weather, higher operating expenses ($8 million), and higher net transmission costs ($3 million), partially offset by higher revenues ($7 million) due to customer growth from the addition of over 52,000 new customers and higher revenues from ancillary services ($2 million). Taxes other than income taxes were lower by $4 million primarily as a result of the Texas margin tax being classified as an income tax for reporting purposes in 2008.

Natural Gas Distribution

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

     The following table provides summary data of our Natural Gas Distribution business segment for the three months ended March 31, 2007 and 2008 (in millions, except throughput and customer data):

		Three Months Ended March 31,
		2007				2008
Revenues		$	1,567			$	1,700
Expenses:
Natural gas			1,212				1,333
Operation and maintenance			147				156
Depreciation and amortization			38				39
Taxes other than income taxes			41				51
Total expenses			1,438				1,579
Operating Income		$	129			$	121
Throughput (in Bcf):
Residential			86				84
Commercial and industrial			81				83
Total Throughput			167				167
Average number of customers:
Residential			2,946,203				2,975,591
Commercial and industrial			245,576				250,988
Total			3,191,779				3,226,579

Three months ended March 31, 2008 compared to three months ended March 31, 2007

     Our Natural Gas Distribution business segment reported operating income of $121 million for the three months ended March 31, 2008 compared to operating income of $129 million for the three months ended March 31, 2007. Operating margin (revenues less cost of gas) increased $12 million primarily due to increases in gross receipts taxes ($9 million) and recovery of energy-efficiency costs ($3 million), both of which are offset by the related expenses. Other margin increases primarily from new rates ($5 million) and customer growth ($3 million), with the addition of nearly 36,000 customers, was entirely offset by the cost of a winter weather hedge and customer conservation ($11 million). Operation and maintenance expenses increased primarily due to the energy efficiency costs above and higher bad debt expense ($2 million) related to higher revenues.

Competitive Natural Gas Sales and Services

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

     The following table provides summary data of our Competitive Natural Gas Sales and Services business segment for the three months ended March 31, 2007 and 2008 (in millions, except throughput and customer data):

		Three Months Ended March 31,
		2007				2008
Revenues		$	1,064			$	1,120
Expenses:
Natural gas			998				1,105
Operation and maintenance			9				8
Depreciation and amortization			––				1
Taxes other than income taxes			1				—
Total expenses			1,008				1,114
Operating Income		$	56			$	6
Throughput (in Bcf):
Wholesale – third parties			94				70
Wholesale – affiliates			3				2
Retail and Pipeline			58				66
Total Throughput			155				138
Average number of customers:
Wholesale			223				154
Retail and Pipeline			6,764				8,338
Total			6,987				8,492

Three months ended March 31, 2008 compared to three months ended March 31, 2007

     Our Competitive Natural Gas Sales and Services business segment reported operating income of $6 million for the three months ended March 31, 2008 compared to $56 million for the three months ended March 31, 2007. The decrease in operating income of $50 million was primarily due to higher operating margins (revenues less natural gas costs) in 2007 related to sales of gas from inventory that was written down to the lower of cost or market in prior periods of $28 million in the first quarter of 2007 compared to $4 million in the first quarter of 2008 for a net decrease of $24 million. Our Competitive Natural Gas Sales and Services business segment purchases and stores natural gas to meet certain future sales requirements and enters into derivative contracts to hedge the economic value of the future sales. The unfavorable mark-to-market accounting for non-trading financial derivatives for the first quarter of 2008 of $22 million versus $8 million for the same period in 2007 accounted for a further net $14 million decrease. The additional decrease in operating income of $12 million in this quarter compared to the same quarter last year was primarily due to a reduction in margin as basis and summer/winter spreads narrowed.

Interstate Pipelines

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

     The following table provides summary data of our Interstate Pipelines business segment for the three months ended March 31, 2007 and 2008 (in millions, except throughput data):

		Three Months Ended March 31,
		2007				2008
Revenues		$	90			$	133
Expenses:
Natural gas			4				15
Operation and maintenance			27				30
Depreciation and amortization			10				12
Taxes other than income taxes			5				5
Total expenses			46				62
Operating Income		$	44			$	71
Throughput (in Bcf ):
Transportation			294				424

Three months ended March 31, 2008 compared to three months ended March 31, 2007

     The Interstate Pipeline business segment reported operating income of $71 million for the three months ended March 31, 2008 compared to $44 million for the same period of 2007. The increase in operating income of $27 million was primarily driven by the new Carthage to Perryville pipeline ($19 million), other transportation and ancillary services ($8 million), and lower other tax expense and refunds ($2 million). These favorable variances in operating income were partially offset by a 2007 gain on sale of excess gas associated with storage enhancement projects ($2 million).

Field Services

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

     The following table provides summary data of our Field Services business segment for the three months ended March 31, 2007 and 2008 (in millions, except throughput data):

		Three Months Ended March 31,
		2007				2008
Revenues		$	39			$	58
Expenses:
Natural gas			(3	)			(2	)
Operation and maintenance			16				11
Depreciation and amortization			3				3
Taxes other than income taxes			1				1
Total expenses			17				13
Operating Income		$	22			$	45
Throughput (in Bcf ):
Gathering			93				98

Three months ended March 31, 2008 compared to three months ended March 31, 2007

     The Field Services business segment reported operating income of $45 million for the three months ended March 31, 2008 compared to $22 million for the same period of 2007. The increase in operating income of $23 million was primarily driven by a one-time gain ($11 million) related to a settlement and contract buyout of one of

our customers and a one-time gain ($6 million) related to the sale of assets, both recognized in the first quarter of 2008. In addition to these one-time items, increased revenues from gas gathering and ancillary services and higher commodity prices were partially offset by increased operating expenses associated with new assets and general cost increases.

     In addition, this business segment recorded equity income of $2 million and $4 million in the three months ended March 31, 2007 and 2008, respectively, from its 50 percent interest in a jointly-owned gas processing plant. These amounts are included in Other – net under the Other Income (Expense) caption.

Other Operations

     The following table shows the operating income (loss) of our Other Operations business segment for the three months ended March 31, 2007 and 2008 (in millions):

		Three Months Ended March 31,
		2007				2008
Revenues		$	2			$	3
Expenses			4				1
Operating Income (Loss)		$	(2	)		$	2

CERTAIN FACTORS AFFECTING FUTURE EARNINGS

     For information on other developments, factors and trends that may have an impact on our future earnings, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Certain Factors Affecting Future Earnings” in Item 7 of Part II and “Risk Factors” in Item 1A of Part I of our 2007 Form 10-K, and “Cautionary Statement Regarding Forward-Looking Information.”

LIQUIDITY AND CAPITAL RESOURCES

Historical Cash Flows

     The following table summarizes the net cash provided by (used in) operating, investing and financing activities for the three months ended March 31, 2007 and 2008:

		Three Months Ended March 31,
		2007				2008
		(in millions)
Cash provided by (used in):
Operating activities		$	264			$	567
Investing activities			(403	)			(312	)
Financing activities			72				(314	)

Cash Provided by Operating Activities

     Net cash provided by operating activities in the first quarter of 2008 increased $303 million compared to the same period in 2007 primarily due to increased net accounts receivable/payable ($178 million) and decreased gas storage inventory ($116 million).

Cash Used in Investing Activities

     Net cash used in investing activities decreased $91 million in the first quarter of 2008 as compared to the same period in 2007 due to decreased capital expenditures of $212 million primarily related to the completion of certain pipeline projects for our Interstate Pipelines business segment, offset by increased investment in unconsolidated affiliates of $105 million primarily related to the Southeast Supply Header (SESH) pipeline project, and increased restricted cash of transition bond companies of $18 million.

Cash Provided by (Used In) Financing Activities

     Net cash used in financing activities in the first quarter of 2008 increased $386 million compared to the same period in 2007 primarily due to decreased borrowings under revolving credit facilities ($231 million), decreased short-term borrowings ($182 million) and increased repayments of long-term debt ($81 million), which were partially offset by increased proceeds from the issuance of long-term debt ($88 million) and increased proceeds from commercial paper ($35 million).

Future Sources and Uses of Cash

     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 regulatory actions. Our principal cash requirements for the remaining nine months of 2008 include the following:

	•		approximately $813 million of capital expenditures;
	•		cash settlement obligations in connection with possible conversions by holders of our 3.75% convertible senior notes, having an aggregate principal amount of $402 million at March 31, 2008 or in connection with the redemption of such notes on May 30, 2008;
	•		maturing long-term debt aggregating approximately $282 million, including $82 million of transition bonds;
	•		the cash purchase of $175 million of pollution control bonds issued on our behalf;
	•		investment in and advances to SESH of approximately $185 million;
	•		dividend payments on CenterPoint Energy common stock and interest payments on debt.

     We expect that borrowings under our credit facilities, the proceeds from the February 2008 issuance of $488 million of transition bonds (discussed below), anticipated cash proceeds from the remarketing of $175 million of pollution control bonds purchased in April 2008 (discussed below) and anticipated cash flows from operations will be sufficient to meet our cash needs in 2008. Cash needs or discretionary financing or refinancing may also result in the issuance of equity or debt securities in the capital markets.

     Transition Bonds. In February 2008, a new special purpose subsidiary of CenterPoint Houston issued approximately $488 million in transition bonds pursuant to a financing order issued by the Texas Utility Commission in September 2007. Through issuance of the transition bonds, CenterPoint Houston securitized transition property of approximately $483 million representing the remaining balance of the CTC adjusted to refund certain unspent environmental retrofit costs and to recover the amount of the fuel reconciliation settlement. Proceeds were used by the special purpose entity to purchase $483 million of transition property from CenterPoint Houston and to pay costs of issuance. Following a subsequent distribution to us, we used the proceeds for general corporate purposes, including the repayment of debt and the making of loans to or investments in affiliates.

     Purchase of Pollution Control Bonds. In April 2008, we purchased $175 million principal amount of pollution control bonds issued on our behalf at 102% of their principal amount. Prior to the purchase, $100 million principal amount of such bonds had a fixed rate of interest of 7.75% and $75 million principal amount of such bonds had a fixed rate of interest of 8%. Depending on market conditions, we expect to remarket both series of bonds, at 100% of their principal amounts, in 2008.

     Convertible Debt.  As of December 31, 2007 and March 31, 2008, the 3.75% convertible senior notes discussed in Note 9(b) to our consolidated financial statements have been included as current portion of long-term debt in our Consolidated Balance Sheets because the last reported sale price of our common stock for at least 20 trading days during the period of 30 consecutive trading days ending on the last trading day of the fourth quarter of 2007 was greater than or equal to 120% of the conversion price of the 3.75% convertible senior notes and therefore, during the

first quarter of 2008, the 3.75% convertible senior notes meet the criteria that make them eligible for conversion at the option of the holders of these notes. During the three months ended March 31, 2008, we issued 4.4 million shares of our common stock and paid cash of approximately $131 million to settle conversions of approximately $133 million principal amount of our 3.75% convertible senior notes. Convertible senior notes aggregating $402 million remained outstanding at March 31, 2008. In April 2008, we issued 0.25 million shares of our common stock and paid cash of approximately $11 million to settle a conversion of approximately $11 million principal amount of our 3.75% convertible notes.

     In April 2008, we announced a call for redemption of our 3.75% convertible senior notes, at 100% of their principal amount, on May 30, 2008. Substantially all of such notes are expected to be converted by holders prior to the redemption date, and substantially all of such conversions are expected to be settled with a cash payment for the principal amount and delivery of shares of our common stock for the excess value due converting holders. If our closing stock price of $15.57 at April 25, 2008 were unchanged at the dates of the conversions, assuming the conversion of approximately $391 million aggregate principal amount of the notes at the current conversion rate, common stock reflecting a conversion premium of $153 million would be issued to the converting holders.  The conversion rate will be increased as a result of our April 24, 2008 declaration of a regular quarterly cash dividend of $0.1825 per share.  Under the terms of the indenture governing the notes, the increased conversion rate will be determined on May 13, 2008.

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

     Prior to the distribution of our ownership in Reliant Energy, Inc. (RRI) to our shareholders, CERC had guaranteed certain contractual obligations of what became RRI’s trading subsidiary. Under the terms of the separation agreement between the companies, RRI agreed to extinguish all such guaranty obligations prior to separation, but at the time of separation in September 2002, RRI had been unable to extinguish all obligations. To secure CERC against obligations under the remaining guaranties, RRI agreed to provide cash or letters of credit for CERC’s benefit, and undertook to use commercially reasonable efforts to extinguish the remaining guaranties. In December 2007, we, CERC and RRI amended that agreement and CERC released the letters of credit it held as security. Under the revised agreement RRI agreed to provide cash or new letters of credit to secure CERC against exposure under the remaining guaranties as calculated under the new agreement if and to the extent changes in market conditions exposed CERC to a risk of loss on those guaranties.

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

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

Amount Utilized at

Date Executed

Company

Type of Facility

Size of Facility

March 31, 2008

Termination Date

June 29, 2007

CenterPoint Energy

Revolver

$

1,200

$

28

(1)

June 29, 2012

June 29, 2007

CenterPoint Houston

Revolver

300

4

(1)

June 29, 2012

June 29, 2007

CERC Corp.

Revolver

950

135

(2)

June 29, 2012

October 30, 2007

CERC

Receivables

375

200

October 28, 2008

     Our $1.2 billion credit facility has a first drawn cost of London Interbank Offered Rate (LIBOR) plus 55 basis points based on our current credit ratings. The facility contains a debt (excluding transition bonds) to earnings before interest, taxes, depreciation and amortization covenant.

     CenterPoint Houston’s $300 million credit facility’s first drawn cost is LIBOR plus 45 basis points based on CenterPoint Houston’s current credit ratings. The facility contains a debt (excluding transition bonds) to total capitalization covenant.

     CERC Corp.’s $950 million credit facility’s first drawn cost is LIBOR plus 45 basis points based on CERC Corp.’s current credit ratings. The facility contains a debt to total capitalization covenant.

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

     We, CenterPoint Houston and CERC Corp. are currently in compliance with the various business and financial covenants contained in the respective receivables and credit facilities.

     Our $1.2 billion credit facility backstops a $1.0 billion CenterPoint Energy commercial paper program under which we began issuing commercial paper in June 2005. The $950 million CERC Corp. credit facility backstops a $950 million commercial paper program under which CERC Corp. began issuing commercial paper in February 2008. As of March 31, 2008, there was no CenterPoint Energy commercial paper outstanding and $35 million of CERC Corp. commercial paper outstanding. The CenterPoint Energy commercial paper is rated “Not Prime” by Moody’s Investors Service, Inc. (Moody’s), “A-2” by Standard & Poor’s Rating Services (S&P), a division of The McGraw-Hill Companies, and “F3” by Fitch, Inc. (Fitch). The CERC Corp. commercial paper is rated “P-3” by Moody’s, “A-2” by S&P, and “F2” by Fitch. As a result of the credit ratings on the two commercial paper programs, we do not expect to be able to rely on the sale of commercial paper to fund all of our short-term borrowing requirements. We cannot assure you that these ratings, or the credit ratings set forth below in “— Impact on Liquidity of a Downgrade in Credit Ratings,” will remain in effect for any given period of time or that one or more of these ratings will not be lowered or withdrawn entirely by a rating agency. We note that these credit ratings are not recommendations to buy, sell or hold our securities and may be revised or withdrawn at any time by the rating agency. Each rating should be evaluated independently of any other rating. Any future reduction or withdrawal of one or more of our credit ratings could have a material adverse impact on our ability to obtain short- and long-term financing, the cost of such financings and the execution of our commercial strategies.

     Securities Registered with the SEC.  As of March 31, 2008, CenterPoint Energy had a shelf registration statement covering senior debt securities, preferred stock and common stock aggregating $750 million and CERC Corp. had a shelf registration statement covering $400 million principal amount of senior debt securities.

     Hedging of Future Debt Issuances.  As of March 31, 2008, we had outstanding treasury rate lock derivative instruments (treasury rate locks) with an aggregate notional amount of $300 million, expiration dates of June 2008 and a weighted-average locked U.S. treasury rate on ten-year debt of 4.05%. These treasury rate locks were executed to hedge the ten-year U.S. treasury rate expected to be used in pricing the forecasted issuance of $300 million of fixed-rate debt in 2008.

     Temporary Investments.  As of March 31, 2008, CERC Corp. had external temporary investments of approximately $4 million.

     Money Pool.  We have a money pool through which the holding company and participating subsidiaries 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 our revolving credit facility or the sale of our commercial paper.

     Impact on Liquidity of a Downgrade in Credit Ratings.  As of April 15, 2008, Moody’s, S&P, and Fitch had assigned the following credit ratings to senior debt of CenterPoint Energy and certain subsidiaries:

Moody’s

S&P

Fitch

Company/Instrument

Rating

Outlook(1)

Rating

Outlook(2)

Rating

Outlook(3)

CenterPoint Energy Senior Unsecured      Debt

Ba1

Stable

BBB-

Stable

BBB-

Stable

CenterPoint Houston Senior Secured      Debt (First Mortgage Bonds)

Baa2

Stable

BBB+

Stable

A-

Stable

CERC Corp. Senior Unsecured Debt

Baa3

Stable

BBB

Stable

BBB

Stable

     A decline in credit ratings could increase borrowing costs under our $1.2 billion credit facility, CenterPoint Houston’s $300 million credit facility and CERC Corp.’s $950 million credit facility. A decline in credit ratings would also increase the interest rate on long-term debt to be issued in the capital markets and could negatively impact our ability to complete capital market transactions. Additionally, a decline in credit ratings could increase cash collateral requirements and reduce earnings of our Natural Gas Distribution and Competitive Natural Gas Sales and Services business segments.

     In September 1999, we issued 2.0% ZENS having an original principal amount of $1.0 billion of which $840 million remain outstanding. Each ZENS note is exchangeable at the holder’s option at any time for an amount of cash equal to 95% of the market value of the reference shares of Time Warner Inc. common stock (TW Common) attributable to each ZENS note. If our creditworthiness were to drop such that ZENS note holders thought our liquidity was adversely affected or the market for the ZENS notes were to become illiquid, some ZENS note holders might decide to exchange their ZENS notes for cash. Funds for the payment of cash upon exchange could be obtained from the sale of the shares of TW Common that we own or from other sources. We own shares of TW Common equal to approximately 100% of the reference shares used to calculate our obligation to the holders of the ZENS notes. ZENS note exchanges result in a cash outflow because deferred tax liabilities related to the ZENS notes and TW Common shares become current tax obligations when ZENS notes are exchanged or otherwise retired and TW Common shares are sold. A tax obligation of approximately $158 million relating to our “original issue discount” deductions on the ZENS would have been payable if all of the ZENS had been exchanged for cash on March 31, 2008. The ultimate tax obligation related to the ZENS notes continues to increase by the amount of the tax benefit realized each year and there could be a significant cash outflow when the taxes are paid as a result of the retirement of the ZENS notes.

     CenterPoint Energy Services, Inc. (CES), a wholly owned subsidiary of CERC Corp. operating in our Competitive Natural Gas Sales and Services business segment, provides comprehensive natural gas sales and services primarily to commercial and industrial customers and electric and gas utilities throughout the central and eastern United States. In order to economically hedge its exposure to natural gas prices, CES uses derivatives with provisions standard for the industry, including those pertaining to credit thresholds. Typically, the credit threshold negotiated with each counterparty defines the amount of unsecured credit that such counterparty will extend to CES. To the extent that the credit exposure that a counterparty has to CES at a particular time does not exceed that credit threshold, CES is not obligated to provide collateral. Mark-to-market exposure in excess of the credit threshold is routinely collateralized by CES. As of March 31, 2008, the amount posted as collateral amounted to approximately $20 million. 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 on two business days’ notice up to the amount of its previously unsecured credit limit. We estimate that as of March 31, 2008, unsecured credit limits extended to CES by counterparties aggregate $180 million; however, utilized credit capacity is significantly lower. In addition, CERC Corp. and its subsidiaries purchase natural gas under supply agreements that contain an aggregate credit threshold of

$100 million based on CERC Corp.’s S&P Senior Unsecured Long-Term Debt rating of BBB. Upgrades and downgrades from this BBB rating will increase and decrease the aggregate credit threshold accordingly.

     In connection with the development of SESH’s 270-mile pipeline project, CERC Corp. has committed that it will advance funds to the joint venture or cause funds to be advanced for its 50% share of the cost to construct the pipeline. CERC Corp. also agreed to provide a letter of credit in an amount up to $400 million for its share of funds that have not been advanced in the event S&P reduces CERC Corp.’s bond rating below investment grade before CERC Corp. has advanced the required construction funds. However, CERC Corp. is relieved of these commitments (i) to the extent of 50% of any borrowing agreements that the joint venture has obtained and maintains for funding the construction of the pipeline and (ii) to the extent CERC Corp. or its subsidiary participating in the joint venture obtains committed borrowing agreements pursuant to which funds may be borrowed and used for the construction of the pipeline. A similar commitment has been provided by the other party to the joint venture. As of March 31, 2008, subsidiaries of CERC Corp. have advanced approximately $305 million to SESH, of which $159 million was in the form of an equity contribution and $146 million was in the form of a loan.

     Cross Defaults.  Under our revolving credit facility, a payment default on, or a non-payment default that permits acceleration of, any indebtedness exceeding $50 million by us or any of our significant subsidiaries will cause a default. In addition, six outstanding series of our senior notes, aggregating $1.3 billion in principal amount as of March 31, 2008, provide that a payment default by us, CERC Corp. or CenterPoint Houston in respect of, or an acceleration of, borrowed money and certain other specified types of obligations, in the aggregate principal amount of $50 million, will cause a default. A default by CenterPoint Energy would not trigger a default under our subsidiaries’ debt instruments or bank credit facilities.

     Other Factors that Could Affect Cash Requirements.  In addition to the above factors, our liquidity and capital resources could be affected by:

	•		cash collateral requirements that could exist in connection with certain contracts, including gas purchases, gas price and weather hedging and gas storage activities of our Natural Gas Distribution and Competitive Natural Gas Sales and Services business segments, particularly given gas price levels and volatility;
	•		acceleration of payment dates on certain gas supply contracts under certain circumstances, as a result of increased gas prices and concentration of natural gas suppliers;
	•		increased costs related to the acquisition of natural gas;
	•		increases in interest expense in connection with debt refinancings and borrowings under credit facilities;
	•		various regulatory actions;
	•		the ability of RRI and its subsidiaries to satisfy their obligations as the principal customers of CenterPoint Houston and 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 CERC is a guarantor;
	•		slower customer payments and increased write-offs of receivables due to higher gas prices or changing economic conditions;
	•		cash payments in connection with the exercise of contingent conversion rights of holders of convertible debt;
	•		the outcome of litigation brought by and against us;
	•		contributions to benefit plans;
	•		restoration costs and revenue losses resulting from natural disasters such as hurricanes; and
	•		various other risks identified in “Risk Factors” in Item 1A of our 2007 Form 10-K.

     Certain Contractual Limits on Our Ability to Issue Securities and Borrow Money. CenterPoint Houston’s credit facility limits CenterPoint Houston’s debt (excluding transition bonds) as a percentage of its total capitalization to 65%. CERC Corp.’s bank facility and its receivables facility limit CERC’s debt as a percentage of its total capitalization to 65%. Our $1.2 billion credit facility contains a debt, excluding transition bonds, to EBITDA covenant. Additionally, CenterPoint Houston has contractually agreed that it will not issue additional first mortgage bonds, subject to certain exceptions.

NEWACCOUNTING PRONOUNCEMENTS

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

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk From Non-Trading Activities

     We use derivative instruments as economic hedges to offset the commodity price exposure inherent in our businesses. The stand-alone commodity risk created by these instruments, without regard to the offsetting effect of the underlying exposure these instruments are intended to hedge, is described below. We measure the commodity risk of our non-trading energy derivatives using a sensitivity analysis. The sensitivity analysis performed on our non-trading energy derivatives measures the potential loss in fair value based on a hypothetical 10% movement in energy prices. At March 31, 2008, the recorded fair value of our non-trading energy derivatives was a net asset of $61 million. The net asset consisted of a net asset of less than $1 million associated with price stabilization activities of our Natural Gas Distribution business segment and a net asset of $60 million related to our Competitive Natural Gas Sales and Services business segment. Net assets or liabilities related to the price stabilization activities correspond directly with net over/under recovered gas cost liabilities or assets on the balance sheet. A decrease of 10% in the market prices of energy commodities from their March 31, 2008 levels would have decreased the fair value of our non-trading energy derivatives net asset by $12 million.

     The above analysis of the non-trading energy derivatives utilized for commodity price risk management purposes does not include the favorable impact that the same hypothetical price movement would have on our physical purchases and sales of natural gas to which the hedges relate. Furthermore, the non-trading energy derivative portfolio is managed to complement the physical transaction portfolio, reducing overall risks within limits. Therefore, the adverse impact to the fair value of the portfolio of non-trading energy derivatives held for hedging purposes associated with the hypothetical changes in commodity prices referenced above is expected to be substantially offset by a favorable impact on the underlying hedged physical transactions.

Interest Rate Risk

     As of March 31, 2008, we had outstanding long-term debt, bank loans, lease obligations, treasury rate lock derivative instruments and obligations under our ZENS that subject us to the risk of loss associated with movements in market interest rates.

     Our floating-rate obligations aggregated $335 million at March 31, 2008. If the floating interest rates were to increase by 10% from March 31, 2008 rates, our combined interest expense would increase by approximately $1 million annually.

     At March 31, 2008, we had outstanding fixed-rate debt (excluding indexed debt securities) aggregating $9.2 billion in principal amount and having a fair value of $9.4 billion. These instruments are fixed-rate and, therefore, do not expose us to the risk of loss in earnings due to changes in market interest rates (please read Note 9 to our consolidated financial statements). However, the fair value of these instruments would increase by approximately $379 million if interest rates were to decline by 10% from their levels at March 31, 2008. In general, such an increase in fair value would impact earnings and cash flows only if we were to reacquire all or a portion of these instruments in the open market prior to their maturity.

     As of March 31, 2008, we had outstanding treasury rate locks with an aggregate notional amount of $300 million, expiration dates of June 2008 and a weighted-average locked U.S. treasury rate on ten-year debt of 4.05%.

These treasury rate locks were executed to hedge the ten-year U.S. treasury rate expected to be used in pricing the forecasted issuance of $300 million of fixed-rate debt in 2008. As of March 31, 2008, the treasury lock derivative instruments could be terminated at a cost of $16 million. The treasury rate locks qualify as cash flow hedges under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS No. 133), and are marked to market in our Consolidated Balance Sheets with changes reflected in accumulated other comprehensive loss. A decrease of 10% in the March 31, 2008 level of interest rates on 10-year U.S. treasury notes would increase the cost of terminating the treasury rate locks outstanding at March 31, 2008 by approximately $9 million.

     Upon adoption of SFAS No. 133, effective January 1, 2001, the ZENS obligation was bifurcated into a debt component and a derivative component. The debt component of $115 million at March 31, 2008 was a fixed-rate obligation and, therefore, did not expose us to the risk of loss in earnings due to changes in market interest rates. However, the fair value of the debt component would increase by approximately $19 million if interest rates were to decline by 10% from levels at March 31, 2008. Changes in the fair value of the derivative component, a $211 million recorded liability at March 31, 2008, are recorded in our Statements of Consolidated Income and, therefore, we are exposed to changes in the fair value of the derivative component as a result of changes in the underlying risk-free interest rate. If the risk-free interest rate were to increase by 10% from March 31, 2008 levels, the fair value of the derivative component liability would increase by approximately $3 million, which would be recorded as an unrealized loss in our Statements of Consolidated Income.

Equity Market Value Risk

     We are exposed to equity market value risk through our ownership of 21.6 million shares of TW Common, which we hold to facilitate our ability to meet our obligations under the ZENS. A decrease of 10% from the March 31, 2008 market value of TW Common would result in a net loss of approximately $4 million, which would be recorded as an unrealized loss in our Statements of Consolidated Income.

Item 4. CONTROLS AND PROCEDURES

     In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our principal executive officer and principal financial officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of March 31, 2008 to provide assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding disclosure.

     There has been no change in our internal controls over financial reporting that occurred during the three months ended March 31, 2008 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 description of certain legal and regulatory proceedings affecting CenterPoint Energy, please read Notes 4 and 10 to our Interim Condensed Financial Statements, each of which is incorporated herein by reference. See also “Business — Regulation” and “ — Environmental Matters” in Item 1 and “Legal Proceedings” in Item 3 of our 2007 Form 10-K.

Item 1A. RISK FACTORS

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

Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

     Conversion of 3.75% Convertible Senior Notes due 2023. Since February 20, 2008, we have issued 533,737 shares of our common stock upon conversion of approximately $21.4 million aggregate principal amount of our 3.75% Convertible Senior Notes due 2023, as set forth in the table below:

Settlement Date			Principal Amount				Number of Shares
of Conversion			of Notes Converted				of Common Stock Issued
March 7, 2008			$	650,000				58,134	(1)
March 12, 2008				10,000,000				227,803	(2)
April 18, 2008				2,000				44	(2)
April 21, 2008				2,000				45	(2)
April 22, 2008				10,718,000				247,664	(2)
April 25, 2008				2,000				47	(2)
			$	21,374,000				533,737

     The shares of our common stock were issued solely to former holders of our 3.75% Convertible Senior Notes due 2023 upon conversion pursuant to the exemption from registration provided under Section 3(a)(9) of the Securities Act of 1933, as amended. This exemption is available because the shares of our common stock were exchanged by us with our existing security holders exclusively where no commission or other remuneration was paid or given directly or indirectly for soliciting such an exchange.

Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

     At the annual meeting of our shareholders held on April 24, 2008, the matters voted upon and the number of votes cast for or against, as well as the number of abstentions and broker non-votes as to such matters (including a separate tabulation with respect to each nominee for office), were as stated below:

     The following nominees for Class III Directors were elected to serve three-year terms expiring at the 2011 annual meeting of shareholders (abstentions and broker non-votes were not counted):

Nominee		For				Against
O. Holcombe Crosswell			272,278,964				5,954,739
Janiece M. Longoria			273,426,876				4,863,309
Thomas F. Madison			270,543,888				7,520,236
Sherman M. Wolff			272,791,233				5,358,604

     Derrill Cody, David M. McClanahan, Robert T. O’Connell, Michael E. Shannon, Donald R. Campbell, Milton Carroll and Peter S. Wareing all continue as directors of CenterPoint Energy.

     The proposal to amend our Articles of Incorporation to phase out our board of directors’ classified structure was approved with 270,351,324 votes for, 7,301,896 votes against, 3,980,338 abstentions and no broker non-votes.

     The appointment of Deloitte & Touche LLP as independent registered public accountants for CenterPoint Energy for 2008 was ratified with 274,156,719 votes for, 4,013,996 votes against, 3,462,844 abstentions and no broker non-votes.