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

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

In July 2008, the Company entered into heating-degree day swaps to mitigate the effect of fluctuations from normal weather on its financial position and cash flows for the 2008/2009 winter heating season. The swaps are based on ten-year normal weather and provide for a maximum payment by either party of ~~$18~~$11 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

Table of ~~the contingent interest component was not material at issuance or at March 31, 2008.~~Contents

~~(6) Goodwill~~

(6)

Goodwill

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

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

~~(7) Comprehensive Income~~

The Company performs its goodwill impairment tests at least annually and evaluates goodwill when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable. The impairment evaluation for goodwill is performed by using a two-step process. In the first step, the fair value of each reporting unit is compared with the carrying amount of the reporting unit, including goodwill. The estimated fair value of the reporting unit is generally determined on the basis of discounted future cash flows. If the estimated fair value of the reporting unit is less than the carrying amount of the reporting unit, then a second step must be completed in order to determine the amount of the goodwill impairment that should be recorded. In the second step, the implied fair value of the reporting unit’s goodwill is determined by allocating the reporting unit’s fair value to all of its assets and liabilities other than goodwill (including any unrecognized intangible assets) in a manner similar to a purchase price allocation. The resulting implied fair value of the goodwill that results from the application of this second step is then compared to the carrying amount of the goodwill and an impairment charge is recorded for the difference.

The Company performed the test at July 1, 2008, the Company’s annual impairment testing date, and determined that no impairment charge for goodwill was required.

(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

	For the Three Months Ended September 30,					For the Nine Months Ended September 30,
	2007		2008			2007			2008
	(in millions)
Net income	$	91	$	136		$	291		$	360
Other comprehensive income (loss):
Adjustment to pension and other postretirement plans (net of tax of $1, $2, $4 and $3)		1		—			5			3
Net deferred gain (loss) from cash flow hedges (net of tax of $3, $-0-, $6 and $2)		6		(1	)		11			(4	)
Reclassification of deferred loss (gain) from cash flow hedges realized in net income (net of tax of $1, $-0-, $10 and $2)		3		—			(14	)		(4	)
Total		10		(1	)		2			(5	)
Comprehensive income	$	101	$	135		$	293		$	355

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~~

	December 31, 2007			September 30, 2008
	(in millions)
SFAS No. 158 incremental effect	$	(48	)	$	(45	)
Net deferred gain (loss) from cash flow hedges		4			(4	)
Total accumulated other comprehensive loss	$	(44	)	$	(49	)

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(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,~~September 30, 2008, ~~328,265,242 shares of CenterPoint Energy common~~

~~stock were issued and 328,265,076~~342,967,651 shares of CenterPoint Energy common stock were ~~outstanding. See Note 9(b) describing the conversion~~issued and 342,967,485 shares of ~~the 3.75% Convertible Senior Notes in the first quarter of 2008.~~CenterPoint Energy common stock were outstanding. Outstanding common shares exclude 166 treasury shares at both December 31, 2007 and ~~March 31,~~September 30, 2008. See Note 9(b) describing the conversion of the 3.75% convertible senior notes in 2008.

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

~~(a) Short-term Borrowings~~

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

~~In October 2007, CERC amended its~~

(a)	Short-term Borrowings

CERC’s receivables facility ~~and extended the termination date to~~terminated on October 28, 2008. The facility size ~~will range~~ranged 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~~tracked the seasonal pattern of receivables in CERC’s natural gas businesses. At ~~March 31,~~September 30, 2008, the facility size was ~~$375~~$150 million. As of December 31, 2007 and ~~March 31,~~September 30, 2008, $232 million and ~~$200~~$150 million, respectively, was advanced for the purchase of receivables under ~~CERC’s~~this receivables facility. Advances under the receivables facility of $150 million were repaid upon termination of the facility. CERC is currently negotiating a new receivables facility to replace the expired facility, but there can be no assurance that a new facility with acceptable terms can be obtained.

~~(b) Long-term Debt~~

~~Revolving Credit Facilities.~~~~As of March 31,~~

(b)	Long-term Debt

Senior Notes. In May 2008, the Company issued $300 million aggregate principal amount of senior notes due in May 2018 with an interest rate of 6.50%. The proceeds from the sale of the senior notes were used for general corporate purposes, including the satisfaction of cash payment obligations in connection with conversions of the Company’s 3.75% convertible senior notes.

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

Revolving Credit Facilities. As of December 31, 2007 and September 30, 2008, the following loan balances were outstanding under the Company’s revolving credit facilities (in millions):

	December 31, 2007		September 30, 2008
CenterPoint Energy $1.2 billion credit facility borrowings	$	131	$	152
CenterPoint Houston $300 million credit facility borrowings		50		171
CERC Corp. $950 million credit facility borrowings		150		745
Total credit facility borrowings outstanding	$	331	$	1,068

In addition, as of both December 31, 2007 and September 30, 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,~~facility and 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~~facility. There was no commercial paper outstanding ~~under its~~that would have been backstopped by the Company’s $1.2 billion credit facility or CERC Corp.’s $950 million credit ~~facility.~~facility at December 31, 2007 and September 30, 2008. The Company, CenterPoint Houston and CERC Corp. were in compliance with all debt covenants as of ~~March 31,~~September 30, 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~~At the time of ~~such~~the announcement, the notes ~~are expected to be converted by~~were convertible at the option of the holders, ~~prior to the redemption date,~~ and substantially all of ~~such conversions are expected~~the notes were submitted for conversion on or prior to ~~be settled with a cash payment for~~ the ~~principal amount and delivery of~~May 30, 2008 redemption date. During the nine months ended September 30, 2008, the Company issued 16.9 million shares of ~~the Company’s~~its common stock ~~for the excess value due converting holders. If the Company’s closing stock price~~and paid

Table of ~~$15.57 at April 25, 2008 were unchanged at the dates of the conversions, assuming the conversion~~Contents

cash of approximately ~~$391~~$532 million ~~aggregate~~to settle conversions of approximately $535 million 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.its 3.75% convertible senior notes.

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.~~2008 or 2009.

~~(10) Commitments and Contingencies~~

~~(a) Natural Gas Supply Commitments~~

(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,~~September 30, 2008 as these contracts meet the SFAS No. 133 exception to be classified as “normal purchases contracts” or do not meet the definition of a derivative. Natural gas supply commitments also include natural gas transportation contracts ~~which~~that do not meet the definition of a derivative. As of ~~March 31,~~September 30, 2008, minimum payment obligations for natural gas supply commitments are approximately ~~$532~~$301 million for the remaining ~~nine~~three months in 2008, ~~$316~~$631 million in 2009, ~~$296~~$302 million in 2010, ~~$279~~$293 million in 2011, ~~$272~~$283 million in 2012 and ~~$1.2~~$1.1 billion after 2012.

~~(b) Legal, Environmental and Other Regulatory Matters~~

(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 “Gas Market Manipulation Cases,” “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.~~Cases. A large number of lawsuits ~~have been~~were filed against numerous gas market participants in a number of federal and ~~remain pending in federal court in Nevada and in~~western state ~~court in California, Missouri and Nevada~~courts in connection with the operation of the ~~electricity and~~ natural gas markets in 2000-2001. The Company’s former affiliate, RRI, was a participant in gas trading in the California and ~~certain other states in 2000-2001, a time of power shortages and significant increases in prices.~~Western markets. These lawsuits, many of which have been filed as class actions, allege violations of state and federal antitrust laws. Plaintiffs in these lawsuits are seeking a variety of forms of relief, including recovery of compensatory damages (in some cases in excess of $1 billion), a trebling of compensatory damages, full consideration damages and attorneys’ fees. The Company and/or Reliant Energy were named in approximately 30 of these lawsuits, which were instituted between 2003 and 2007. In October 2006, RRI reached a settlement of 11 class action natural gas cases pending in state court in California. The court approved this settlement in June 2007. In the other gas cases consolidated in state court in California, the Court of Appeals found that the Company was not a successor to the liabilities of a subsidiary of RRI, and the Company was dismissed from these suits in April 2008. In the Nevada federal litigation, three of the complaints were dismissed based on defendants’ filed rate doctrine defense, but the Ninth Circuit Court of Appeals reversed those dismissals and remanded the cases back to the district court for further proceedings. In July 2008, the plaintiffs in four of the federal court cases agreed to dismiss the Company from those cases. In August 2008, the plaintiffs in five additional cases also agreed to dismiss the Company from those cases, but one of these plaintiffs has moved to amend its complaint to add CenterPoint Energy Services, Inc., a subsidiary of the Company, as a defendant in that case. As a result, the Company remains a party in only two remaining gas market manipulation cases, one pending in Nevada state court in Clark County and one in

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federal district court in Nevada. The Company believes it is not a proper defendant in the remaining cases and will continue to pursue dismissal from those cases.

Electricity Market Manipulation Cases. A large number of lawsuits were filed against numerous market participants in connection with the operation of the California electricity markets in 2000-2001. The Company’s former affiliate, 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 was a defendant in approximately five of these suits. These lawsuits, many of which were filed as class actions, were 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~~were pending. Two parties ~~have~~ appealed the courts’ approval of the settlement to the California Court of ~~Appeals.~~Appeals, but that appeal was denied and the deadline to appeal to the California Supreme Court has passed. 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.~~claims.

~~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 Corp., 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

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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 Corp., 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 Corp., EGMC and other defendants in the Miller County case filed a petition in a district court in Travis County, Texas seeking a determination that the Railroad Commission has exclusive original ~~exclusive~~ jurisdiction over the Texas claims asserted in the Miller County case. In October 2007, CEFS and CEPS ~~were~~ joined ~~as plaintiffs to~~the petition in the Travis County case. In October 2008, the district court ruled that the Railroad Commission had exclusive original jurisdiction over the Texas claims asserted against the Company, CERC Corp., EGMC and the other defendants in the Miller County case. The time has not yet run for an appeal of this ruling.

In August 2007, the Arkansas plaintiff in the Miller County litigation initiated a complaint at the APSC seeking a decision concerning the extent of the APSC’s jurisdiction over the Miller County case and an investigation into the merits of the allegations asserted in his complaint with respect to 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~~were stayed pending the resolution of the petitions filed with the LPSC. In August 2007, the LPSC issued an order approving a Stipulated Settlement in the review initiated by the plaintiffs in the Calcasieu Parish litigation. In the LPSC proceeding, 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 refund will be completed in the ~~Company began refunding that amount to jurisdictional customers in September 2007.~~fourth quarter of 2008. 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~~ In October 2008, the ~~plaintiffs in~~courts considering the Caddo and Calcasieu Parish cases dismissed these cases ~~includes injunctive and declaratory relief, restitution~~pursuant to motions to dismiss. Although the time for ~~the alleged overcharges, exemplary damages or trebling~~appeal of ~~actual damages, civil penalties and attorney’s fees. The Company,~~that dismissal has not run, 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~~believes these proceedings 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.substantially concluded.

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

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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,~~September 30, 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,~~September 30, 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

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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.

Groundwater Contamination Litigation. Predecessor entities of CERC, along with several other entities, are defendants in litigation, St. Michel Plantation, LLC, et al, v. White, et al., pending in civil district court in Orleans Parish, Louisiana. In the lawsuit, the plaintiffs allege that their property in Terrebonne Parish, Louisiana suffered salt water contamination as a result of oil and gas drilling activities conducted by the defendants. Although a predecessor of CERC held an interest in two oil and gas leases on a portion of the property at issue, neither it nor any other CERC entities drilled or conducted other oil and gas operations on those leases. In July 2008, experts for the plaintiffs filed a report in this litigation in which they claimed that it would cost approximately $105 million to remediate the alleged contamination on property covered by the leases in which the defendants, including CERC’s predecessor company, held interests. CERC’s experts, however, believe that the claims of plaintiffs’ experts are greatly exaggerated and that actual costs for remediation would be materially less than the amounts asserted in the report of the plaintiffs’ experts. CERC is disputing responsibility for remediation of this property and does not expect the outcome of this litigation to have a material adverse impact on the financial condition, results of operations or cash flows of either the Company or CERC.

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~~

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

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the event market conditions change adversely, the Company would retain exposure to the counterparty under the guaranty.

~~(11) Income Taxes~~

(11)	Income Taxes

During the three months and nine months ended ~~March 31,~~September 30, 2007, the effective tax rate was 37% and 35%, respectively. During the three months and nine months ended September 30, 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$2 million and $9 million for the three and nine months ended September 30, 2008, respectively, 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,~~September 30, 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~~

	December 31, 2007		September 30, 2008
Liability for uncertain tax positions	$	82	$	102
Portion of liability for uncertain tax positions that, if recognized, would reduce the effective income tax rate		10		13
Interest accrued on uncertain tax positions		4		8

(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		For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	(in millions, except share and				2007		2008		2007		2008
	per share amounts)				(in millions, except share and per share amounts)
Basic earnings per share calculation:
Net income	$	130	$	123	$	91	$	136	$	291	$	360

Weighted average shares outstanding		318,060,000		327,279,000		321,192,000		342,228,000		320,071,000		333,652,000


Basic earnings per share:
Net income	$	0.41	$	0.38

Basic earnings per share					$	0.29	$	0.40	$	0.91	$	1.08

Diluted earnings per share calculation:
Net income	$	130	$	123	$	91	$	136	$	291	$	360


Weighted average shares outstanding		318,060,000		327,279,000		321,192,000		342,228,000		320,071,000		333,652,000
Plus: Incremental shares from assumed conversions:
Stock options (1)		1,237,000		869,000		1,027,000		841,000		1,104,000		846,000
Restricted stock		1,328,000		1,127,000
Restricted stock units						1,713,000		1,515,000		1,713,000		1,515,000
2.875% convertible senior notes		1,179,000		—		—		—		389,000		—
3.75% convertible senior notes		18,299,000		10,173,000		17,042,000		—		18,945,000		6,174,000

Weighted average shares assuming dilution		340,103,000		339,448,000		340,974,000		344,584,000		342,222,000		342,187,000


Diluted earnings per share:
Net income	$	0.38	$	0.36

Diluted earnings per share					$	0.27	$	0.39	$	0.85	$	1.05

__________


(1)		Options to purchase ~~3,752,647 and 2,848,340~~3,474,562 shares were outstanding for both the three and nine months ended ~~March 31,~~September 30, 2007, and options to purchase 2,720,083 shares were outstanding for both the three and nine months ended September 30, 2008, ~~respectively,~~ but were not included in the computation of diluted earnings per share because the options’ exercise price was greater than the average market price of the common shares for the respective periods.

Substantially all of the Company’s 3.75% contingently convertible senior notes ~~provide~~provided for settlement of the principal portion in cash rather than stock. In accordance with ~~EITF~~Emerging Issues Task Force Issue No. 04-8, “Accounting Issues related to Certain Features of Contingently Convertible Debt and the Effect on Diluted Earnings

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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~~included 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~~exceeded the conversion price. ~~The conversion price~~In April 2008, the Company announced a call for ~~the~~redemption of its 3.75% ~~contingently~~ convertible senior notes on May 30, 2008. At the time of the announcement, the notes were convertible at ~~March 31,~~the option of the holders, and substantially all of the notes were submitted for conversion on or prior to the May 30, 2008 ~~was $11.18.~~redemption date. During the nine months ended September 30, 2008, the Company issued 16.9 million shares of its common stock and paid cash of approximately $532 million to settle conversions of approximately $535 million principal amount of its 3.75% convertible senior notes.

~~(13) Reportable Business Segments~~

(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,			For the Three Months Ended September 30, 2007
	Customers			Revenues			Income (Loss)		2008			Revenues from External Customers			Net Intersegment Revenues			Operating Income (Loss)
Electric Transmission & Distribution	$	409	⁽¹⁾	$	—		$	91	$	8,221		$	528	(1)	$	—		$	196
Natural Gas Distribution		1,697			3			121		4,171			457			1			(8	)
Competitive Natural Gas Sales and Services		1,109			11			6		1,316			758			12			4
Interstate Pipelines		91			42			71		3,087			100			37			70
Field Services		54			4			45		724			36			8			26
Other Operations		3			—			2		2,050	⁽²⁾		3			—			(1	)
Eliminations		—			(60	)		—		(2,034	)		—			(58	)		—

Consolidated	$	3,363		$	—		$	336	$	17,535		$	1,882		$	—		$	287

	For the Three Months Ended September 30, 2008
	Revenues from External Customers			Net Intersegment Revenues			Operating Income (Loss)
Electric Transmission & Distribution	$	552	(1)	$	—		$	202
Natural Gas Distribution		548			2			(6	)
Competitive Natural Gas Sales and Services		1,256			13			35
Interstate Pipelines		96			47			55
Field Services		60			11			44
Other Operations		3			—			7
Eliminations		—			(73	)		—
Consolidated	$	2,515		$	—		$	337

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	For the Nine Months Ended September 30, 2007
	Revenues from External Customers			Net Intersegment Revenues			Operating Income			Total Assets as of December 31, 2007
Electric Transmission & Distribution	$	1,399	(1)	$	—		$	457		$	8,358
Natural Gas Distribution		2,594			7			129			4,332
Competitive Natural Gas Sales and Services		2,679			36			56			1,221
Interstate Pipelines		247			101			166			3,007
Field Services		94			31			75			669
Other Operations		8			—			(1	)		1,956	(2)
Eliminations		—			(175	)		—			(1,671	)
Consolidated	$	7,021		$	—		$	882		$	17,872

	For the Nine Months Ended September 30, 2008
	Revenues from External Customers			Net Intersegment Revenues			Operating Income			Total Assets as of September 30, 2008
Electric Transmission & Distribution	$	1,471	(1)	$	—		$	457	(3)	$	9,141
Natural Gas Distribution		2,969			7			119			4,354
Competitive Natural Gas Sales and Services		3,599			33			36			1,193
Interstate Pipelines		337			131			227	(4)		3,539
Field Services		164			27			121	(5)		792
Other Operations		8			—			10			1,736	(2)
Eliminations		—			(198	)		—			(1,723	)
Consolidated	$	8,548		$	—		$	970		$	19,032

________


(1)		Sales to subsidiaries of RRI in each of the three months ended ~~March 31,~~September 30, 2007 and 2008 represented approximately ~~$149~~$196 million and ~~$142~~$199 million, respectively, of CenterPoint Houston’s transmission and distribution revenues. Sales to subsidiaries of RRI in the nine months ended September 30, 2007 and 2008 represented approximately $496 million and $492 million, respectively.

(2)

Included in total assets of Other Operations as of December 31, 2007 and ~~March 31,~~September 30, 2008 are pension assets of $231 million and ~~$236~~$247 million, respectively. Also included in total assets of Other Operations as of December 31, 2007 and ~~March 31,~~September 30, 2008, are ~~pension related~~pension-related regulatory assets of $319 million and ~~$317~~$311 million, respectively, ~~resulting~~which resulted from the Company’s adoption of SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — An Amendment of FASB Statements No. 87, 88, 106 and 132(R).”.

~~(14) Subsequent Event~~

(3)	Included in operating income of Electric Transmission & Distribution for the nine months ended September 30, 2008 is a $9 million gain on sale of land.

(4)

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

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

(14)	Subsequent Event

On ~~April 24,~~October 30, 2008, the Company’s board of directors declared a regular quarterly cash dividend of $0.1825 per share of common stock payable on ~~June~~December 10, 2008, to shareholders of record as of the close of business on ~~May 16,~~November 14, 2008.

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

EXECUTIVE SUMMARY

Recent Events

Hurricane Ike

The electric delivery system of our electric transmission and distribution subsidiary, CenterPoint Energy Houston Electric, LLC (CenterPoint Houston), suffered substantial damage as a result of Hurricane Ike, which struck the upper Texas coast early Saturday, September 13, 2008.

The strong Category 2 storm initially left more than 90 percent of CenterPoint Houston’s more than 2 million metered customers without power, the largest outage in CenterPoint Houston’s 130-year history. Most of the widespread power outages were due to power lines damaged by downed trees and debris blown by Hurricane Ike’s hurricane-force wind. In addition, on Galveston Island and along the coastal areas of the Gulf of Mexico and Galveston Bay, the storm surge and flooding from rains accompanying the storm caused significant damage or destruction of houses and businesses served by CenterPoint Houston.

CenterPoint Houston estimates that total costs to restore the electric delivery facilities damaged as a result of Hurricane Ike will be in the range of $650 million to $750 million. As is common with electric utilities serving coastal regions, the poles, towers, wires, street lights and pole mounted equipment that comprise CenterPoint Houston’s transmission and distribution system are not covered by property insurance, but office buildings and warehouses and their contents and substations are covered by insurance that provides for a maximum deductible of $10 million. Current estimates are that total losses to property covered by this insurance were approximately $25 million.

In addition to storm restoration costs, CenterPoint Houston estimates that it lost approximately $17 million in revenue through September 30, 2008, and will continue to lose minor amounts of revenue that would otherwise have been anticipated from those customers whose service will not be restored for a longer period. Within the first 18 days after the storm, CenterPoint Houston had restored power to all customers capable of receiving it.

CenterPoint Houston is deferring the uninsured storm restoration costs as management believes it is probable that such costs will be recovered through the regulatory process. As a result, storm restoration costs will not affect our or CenterPoint Houston’s reported net income for 2008. As of September 30, 2008, CenterPoint Houston recorded an increase of $141 million in construction work in progress and $434 million in regulatory assets for restoration costs incurred through September 30, 2008. Approximately $503 million of these costs are based on estimates and are included in accounts payable as of September 30, 2008. Additional restoration costs will continue to be incurred during the fourth quarter of 2008 and possibly during the first quarter of 2009.

Assuming necessary enabling legislation is enacted by the Texas Legislature in the session that begins in January 2009, CenterPoint Houston expects to obtain recovery of its storm restoration costs through the issuance of non-recourse securitization bonds similar to the storm recovery bonds issued by another Texas utility following Hurricane Rita. Assuming those bonds are issued, CenterPoint Houston will recover the amount of storm restoration costs approved by the Public Utility Commission of Texas out of the bond proceeds, with the bonds being repaid over time through a charge imposed on customers. Alternatively, if securitization is not available, recovery of those costs would be sought through traditional regulatory mechanisms. Under its 2006 rate case settlement, CenterPoint Houston is entitled to seek an adjustment to rates in this situation, even though in most instances its rates are frozen until 2010.

The natural gas distribution business (Gas Operations) of CenterPoint Energy Resources Corp. (CERC Corp., and, together with its subsidiaries, CERC) also suffered some damage to its system in Houston, Texas and in other portions of its service territory across Texas and Louisiana. As of September 30, 2008, Gas Operations has deferred

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approximately $3 million of costs related to Hurricane Ike for recovery as part of future natural gas distribution rate proceedings.

CERC Receivables Facility

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

Interstate Pipeline Expansion

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

CONSOLIDATED RESULTS OF OPERATIONS

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

Three Months Ended September 30,
Nine Months Ended
September 30,

2007 2008 2007 2008
Revenues $ 1,882 $ 2,515 $ 7,021 $ 8,548
Expenses 1,595 2,178 6,139 7,578
Operating Income 287 337 882 970
Interest and Other Finance Charges (126 ) (116 ) (368 ) (344 )
Interest on Transition Bonds (30 ) (34 ) (93 ) (102 )
Other Income, net 14 26 24 49
Income Before Income Taxes 145 213 445 573
Income Tax Expense (54 ) (77 ) (154 ) (213 )
Net Income $ 91 $ 136 $ 291 $ 360

Basic Earnings Per Share $ 0.29 $ 0.40 $ 0.91 $ 1.08

Diluted Earnings Per Share $ 0.27 $ 0.39 $ 0.85 $ 1.05

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

We reported consolidated net income of $136 million ($0.39 per diluted share) for the three months ended September 30, 2008 as compared to $91 million ($0.27 per diluted share) for the same period in 2007. The increase in net income of $45 million was primarily due to increased operating income of $31 million in our Competitive Natural Gas Sales and Services business segment, increased operating income of $18 million in our Field Services business segment, decreased interest expense of $10 million, excluding transition bonds, and increased equity earnings of $18 million included in Other Income, net, partially offset by decreased operating income of $15 million in our Interstate Pipelines business segment.

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

We reported consolidated net income of $360 million ($1.05 per diluted share) for the nine months ended September 30, 2008 as compared to $291 million ($0.85 per diluted share) for the same period in 2007. The increase in net income of $69 million was primarily due to increased operating income of $61 million in our Interstate Pipelines business segment, increased operating income of $46 million in our Field Services business segment, increased equity earnings of $36 million included in Other Income, net, and decreased interest expense of $24 million, excluding interest on transition bonds, partially offset by decreased operating income of $20 million in our Competitive Natural Gas Sales and Services business segment, decreased operating income of $10 million in our Natural Gas Distribution business segment and decreased operating income of $10 million from our electric transmission and distribution utility, excluding the transition bond companies.

Income Tax Expense

During the three months and nine months ended September 30, 2007, the effective tax rate was 37% and 35%, respectively. During the three months and nine months ended September 30, 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 $2 million and $9 million for the three and nine months ended September 30, 2008, respectively, 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 and nine months ended September 30, 2007 and 2008.

Three Months Ended
September 30,

Nine Months Ended
September 30,

2007 2008 2007 2008
Electric Transmission & Distribution $ 196 $ 202 $ 457 $ 457
Natural Gas Distribution (8 ) (6 ) 129 119
Competitive Natural Gas Sales and Services 4 35 56 36
Interstate Pipelines 70 55 166 227
Field Services 26 44 75 121
Other Operations (1 ) 7 (1 ) 10
Total Consolidated Operating Income $ 287 $ 337 $ 882 $ 970

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).

~~EXECUTIVE SUMMARY~~

~~Recent Events~~

~~Debt Financing Transactions~~ and “Risk Factors” in Item 1A of Part II of this Quarterly Report on Form 10-Q.

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The following tables provide summary data of our Electric Transmission & Distribution business segment for the three and nine months ended September 30, 2007 and 2008 (in millions, except throughput and customer data):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2007		2008		2007		2008
Revenues:
Electric transmission and distribution utility	$	445	$	455	$	1,187	$	1,220
Transition bond companies		83		97		212		251
Total revenues		528		552		1,399		1,471
Expenses:
Operation and maintenance, excluding transition bond companies		163		167		467		502
Depreciation and amortization, excluding transition bond companies		58		71		182		208
Taxes other than income taxes		58		48		171		153
Transition bond companies		53		64		122		151
Total expenses		332		350		942		1,014
Operating Income	$	196	$	202	$	457	$	457

Operating Income:
Electric transmission and distribution utility	$	155	$	169	$	335	$	352
Competition transition charge		11		—		32		5
Transition bond companies (1)		30		33		90		100
Total segment operating income	$	196	$	202	$	457	$	457

Throughput (in gigawatt-hours (GWh)):
Residential		8,381		8,446		19,060		19,623
Total		22,726		21,594		58,561		58,523

Average number of metered customers:
Residential		1,782,281		1,822,351		1,767,431		1,812,821
Total		2,022,448		2,066,538		2,006,344		2,055,723

___________

(1) Represents the amount necessary to pay interest on the transition bonds.

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

Our Electric Transmission & Distribution business segment reported operating income of $202 million for the three months ended September 30, 2008, consisting of $169 million from the regulated electric transmission and distribution utility (TDU) and $33 million related to transition bond companies. For the three months ended September 30, 2007, operating income totaled $196 million, consisting of $155 million from the TDU, exclusive of an additional $11 million from the competition transition charge (CTC), and $30 million related to transition bond companies. Revenues for the TDU increased due to increased usage ($13 million), continued customer growth ($8 million), with over 42,000 metered customers added since September 30, 2007, and increased transmission-related revenues ($5 million), partially offset by the loss of revenues due to Hurricane Ike ($17 million). Operation and maintenance expense increased primarily due to higher transmission costs ($6 million) and increased support services ($2 million), partially offset by normal operating and maintenance expenses that were postponed as a result of Hurricane Ike restoration efforts ($5 million). Depreciation and amortization increased $13 million primarily due to amounts related to the CTC, which were offset by similar amounts in revenues ($11 million). Taxes other than income taxes declined $10 million as a result of Texas margin taxes being classified as an income tax for financial reporting purposes in 2008 ($5 million) and a refund of prior year state franchise taxes ($5 million).

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

Our Electric Transmission & Distribution business segment reported operating income of $457 million for the nine months ended September 30, 2008, consisting of $352 million from the TDU, exclusive of an additional $5 million from the CTC, and $100 million related to transition bond companies. For the nine months ended

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September 30, 2007, operating income totaled $457 million, consisting of $335 million from the TDU, exclusive of an additional $32 million from the CTC, and $90 million related to transition bond companies. Revenues for the TDU increased due to customer growth, with over 42,000 metered customers added since September 30, 2007 ($20 million), increased usage ($18 million) primarily caused by favorable weather experienced in 2008 net of conservation, increased transmission-related revenues ($14 million) and increased ancillary services ($6 million), partially offset by the reduced revenues due to Hurricane Ike ($17 million) and the settlement of the final fuel reconciliation in 2007 ($4 million). Operation and maintenance expense increased primarily due to higher transmission costs ($22 million), the settlement of the final fuel reconciliation in 2007 ($13 million) and increased support services ($10 million), partially offset by a gain on sale of land ($9 million) and normal operating and maintenance expenses that were postponed as a result of Hurricane Ike restoration efforts ($5 million). Depreciation and amortization increased $26 million primarily due to amounts related to the CTC, which were offset by similar amounts in revenues ($21 million). Taxes other than income taxes declined $18 million primarily as a result of the Texas margin tax being classified as an income tax for financial reporting purposes in 2008 ($16 million) and a refund of prior year state franchise taxes ($5 million).

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

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2008			2007		2008
Revenues	$	458		$	550		$	2,601	$	2,976
Expenses:
Natural gas		267			351			1,845		2,196
Operation and maintenance		139			139			421		436
Depreciation and amortization		38			40			114		118
Taxes other than income taxes		22			26			92		107
Total expenses		466			556			2,472		2,857
Operating Income (Loss)	$	(8	)	$	(6	)	$	129	$	119

Throughput (in Bcf):
Residential		12			13			118		117
Commercial and industrial		42			41			168		171
Total Throughput		54			54			286		288

Average number of customers:
Residential		2,910,041			2,937,618			2,927,122		2,956,500
Commercial and industrial		246,021			245,514			246,382		248,759
Total		3,156,062			3,183,132			3,173,504		3,205,259

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

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

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

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

Competitive Natural Gas Sales and Services

For information regarding factors that may affect the future results of operations of our Competitive Natural Gas Sales and Services business segment, please read “Risk Factors — Risk Factors Affecting Our 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 and “Risk Factors” in Item 1A of Part II of this Quarterly Report on Form 10-Q.

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2007		2008		2007		2008
Revenues	$	770	$	1,269	$	2,715	$	3,632
Expenses:
Natural gas		756		1,225		2,631		3,567
Operation and maintenance		7		8		23		26
Depreciation and amortization		3		1		4		2
Taxes other than income taxes		—		—		1		1
Total expenses		766		1,234		2,659		3,596
Operating Income	$	4	$	35	$	56	$	36

Throughput (in Bcf)		119		125		393		392

Average number of customers		6,976		9,245		7,014		8,974

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

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

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

Our Competitive Natural Gas Sales and Services business segment reported operating income of $36 million for the nine months ended September 30, 2008 compared to $56 million for the nine months ended September 30, 2007,

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

Interstate Pipelines

For information regarding factors that may affect the future results of operations of our Interstate Pipelines business segment, please read “Risk Factors — Risk Factors Affecting Our 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 and “Risk Factors” in Item 1A of Part II of this Quarterly Report on Form 10-Q.

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

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

Transportation throughput (in Bcf) :		312		360		880		1,145

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

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

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

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

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

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

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

Gathering throughput (in Bcf) :		104			109		297			311

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

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

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

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

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

In addition, this business segment recorded equity income of $6 million and $12 million in the nine months ended September 30, 2007 and 2008, respectively, from its 50 percent interest in a jointly-owned gas processing plant. These amounts are included in Other, net under the Other Income (Expense) caption.

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Other Operations

The following table shows the operating income of our Other Operations business segment for the three and nine months ended September 30, 2007 and 2008 (in millions):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2008			2007			2008
Revenues	$	3		$	3		$	8		$	8
Expenses		4			(4	)		9			(2	)
Operating Income (Loss)	$	(1	)	$	7		$	(1	)	$	10

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, “Cautionary Statement Regarding Forward-Looking Information” and “Risk Factors” in this Quarterly Report on Form 10-Q.

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 nine months ended September 30, 2007 and 2008:

	Nine Months Ended September 30,
	2007			2008
	(in millions)
Cash provided by (used in):
Operating activities	$	492		$	724
Investing activities		(933	)		(991	)
Financing activities		368			222

Cash Provided by Operating Activities

Net cash provided by operating activities in the first nine months of 2008 increased $232 million compared to the same period in 2007 primarily due to increased cash provided by net accounts receivable/payable ($242 million), increased fuel cost recovery ($79 million), increased net income ($69 million) and decreased tax payments ($7 million), partially offset by increased net margin deposits ($145 million), increased net regulatory assets and liabilities ($105 million) and increased gas storage inventory ($33 million).

Cash Used in Investing Activities

Net cash used in investing activities increased $58 million in the first nine months of 2008 as compared to the same period in 2007 primarily due to increased investment in unconsolidated affiliates ($167 million) and increased notes receivable from unconsolidated affiliates ($124 million) primarily related to the SESH pipeline project, and increased restricted cash of transition bond companies ($8 million), offset by decreased capital expenditures ($219 million) primarily related to the completion of certain pipeline projects for our Interstate Pipelines business segment.

Cash Provided by Financing Activities

Net cash provided by financing activities in the first nine months of 2008 decreased $146 million compared to the same period in 2007 primarily due to decreased short-term borrowings ($45 million), decreased net proceeds from commercial paper ($76 million), increased repayments of long-term debt ($864 million), which were partially

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offset by increased proceeds from long-term debt ($688 million), and increased net borrowings under long-term revolving credit facilities ($157 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 three months of 2008 include the following:

approximately $385 million of capital requirements;

estimated restoration costs related to Hurricane Ike of approximately $600 million;

investment in and advances to SESH of approximately $30 million; and

dividend payments on CenterPoint Energy common stock and interest payments on debt.

In addition to these cash requirements, we expect to receive a tax refund of approximately $75 million in the remaining three months of 2008.

We expect that borrowings under our credit facilities, tax refunds 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 or the arrangement of additional credit facilities. Issuances of equity or debt in the capital markets and additional credit facilities may not, however, be available to us on acceptable terms.

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.~~2008 or 2009.

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


~~(1)~~		~~Represents the amount necessary to pay interest on the transition bonds.~~

~~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~~

	•		~~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.

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.

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Credit and Receivables Facilities. As of ~~March~~October 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

Company

Type of Facility

Size of Facility

Amount Utilized at

October 31, 2008

Termination Date

June 29, 2007

CenterPoint Energy

Revolver

1,200

⁽¹⁾

June 29, 2012

CenterPoint Energy

Revolver

1,200

(1)

308

(2)

June 29, 2012

June 29, 2007

CenterPoint Houston

Revolver

300

⁽¹⁾

June 29, 2012

CenterPoint Houston

Revolver

300

(1)

247

(3)

June 29, 2012

June 29, 2007

CERC Corp.

Revolver

950

135

⁽²⁾

June 29, 2012

CERC Corp.

Revolver

950

(1)

919

June 29, 2012

October 30, 2007

CERC

Receivables

375

200

October 28, 2008

________

(1)Lehman Brothers Bank, FSB, which had an approximately four percent participation in our credit facility and each of the credit facilities of CenterPoint Houston and CERC Corp., stopped funding its commitments following the bankruptcy filing of its parent in September 2008, effectively causing a reduction to the total available capacity of $44 million under our facility, $8 million under CenterPoint Houston's facility and $20 million under CERC Corp.'s facility. Effective November 7, 2008, we are terminating Lehman Brothers Bank, FSB, as a participating lender under our facility and CenterPoint Houston's facility, thereby causing a permanent reduction in the capacity of those facilities from the amounts shown in this column.

(2) Includes $281 million of borrowings and $27 million of outstanding letters of credit.


~~(1)~~		~~Represents outstanding letters of credit.~~

~~(2)~~		~~Includes $100 million of borrowings under the credit facility and $35 million of outstanding commercial paper supported by the CERC Corp. credit facility.~~

(3) Includes $243 million of borrowings and $4 million of outstanding letters of credit.

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.~~(EBITDA) covenant, which was modified in August 2008 so that the permitted ratio of debt to EBITDA will continue at its current level for the remaining term of the facility.

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

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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,~~ In October 2008, CenterPoint Energy ~~had~~and CenterPoint Houston jointly registered indeterminate principal amounts of CenterPoint Houston’s general mortgage bonds and CenterPoint Energy’s senior debt securities and junior subordinated debt securities and an indeterminate number of CenterPoint Energy’s shares of common stock, shares of preferred stock, as well as stock purchase contracts and equity units. In addition, CERC Corp. has 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~~$500 million principal amount of senior debt ~~securities.~~securities as a result of its registration statement filed in August 2008.

~~Hedging of Future Debt Issuances.~~

Temporary Investments. As of ~~March~~October 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~~no external temporary ~~investments of approximately $4 million.~~investments.

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~~CenterPoint Energy’s revolving credit facility or the sale of our commercial paper.

Impact on Liquidity of a Downgrade in Credit Ratings. As of ~~April 15,~~October 31, 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

CenterPoint Houston Senior Secured

Debt (General Mortgage Bonds)

Baa2

Stable

BBB+

Stable

BBB+

Stable

CERC Corp. Senior Unsecured Debt

Baa3

Stable

BBB

Stable

BBB

Stable

__________


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

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

(3)

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

In October 2008, Moody’s affirmed the credit ratings and stable outlook for CenterPoint Energy, CenterPoint Houston and CERC Corp. In October 2008, S&P published a report which confirmed the credit rating and stable outlook of CenterPoint Energy.

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~~Zero-Premium Exchangeable Subordinated Notes due 2029 (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

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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~~$174 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,~~September 30, 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,~~September 30, 2008, the amount posted as collateral amounted to approximately ~~$20~~$143 million. Should the credit ratings of CERC Corp. ~~(as the~~(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 utilized amount of its previously unsecured credit limit. We estimate that as of ~~March 31,~~September 30, 2008, unsecured credit limits extended to CES by counterparties aggregate ~~$180~~$175 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~~ $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~~advanced 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,~~September 30, 2008, subsidiaries of CERC Corp. have advanced approximately ~~$305~~$582 million to SESH, of which ~~$159~~$266 million was in the form of an equity contribution and ~~$146~~$316 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~~four outstanding series of our senior notes, aggregating ~~$1.3 billion~~$950 million in principal amount as of ~~March 31,~~September 30, 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.

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

Pension Plan Costs. Net periodic pension costs will likely increase in 2009 due to decreases in pension plan assets as a result of recent declines in global equity and fixed income markets. Pension expense increases approximately $12 million for every 5% decline in plan assets.

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

	•	·	cash collateral requirements that could exist in connection with certain contracts, including gas purchases, gas price ~~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;

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	•	·	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;~~hurricanes and the timing of recovery of such restoration costs; and

•

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

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~~

NEW ACCOUNTING 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,~~September 30, 2008, the recorded fair value of our non-trading energy derivatives was a net ~~asset~~liability of ~~$61 million.~~$79 million (before collateral). The net ~~asset~~liability consisted of a net ~~asset~~liability of ~~less than $1~~$121 million associated with price stabilization activities of our Natural Gas Distribution business segment and a net asset of ~~$60~~$42 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,~~September 30, 2008 levels would have decreased the fair value of our non-trading energy derivatives net ~~asset~~liability by ~~$12~~$75 million. However, the

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consolidated income statement impact of this same 10% decrease in market prices would be a reduction in income of $5 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,~~September 30, 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~~$1.2 billion at ~~March 31,~~September 30, 2008. If the floating interest rates were to increase by 10% from ~~March 31,~~September 30, 2008 rates, our combined interest expense would increase by approximately $1$4 million annually.

At ~~March 31,~~September 30, 2008, we had outstanding fixed-rate debt (excluding indexed debt securities) aggregating ~~$9.2~~$8.9 billion in principal amount and having a fair value of ~~$9.4~~$8.7 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~~$331 million if interest rates were to decline by 10% from their levels at ~~March 31,~~September 30, 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.

Upon adoption 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,~~Activities,” effective January 1, 2001, the ZENS obligation was bifurcated into a debt component and a derivative component. The debt component of ~~$115~~$117 million at ~~March 31,~~September 30, 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,~~September 30, 2008. Changes in the fair value of the derivative component, a ~~$211~~$195 million recorded liability at ~~March 31,~~September 30, 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,~~September 30, 2008 levels, the fair value of the derivative component liability would increase by approximately $3$4 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,~~September 30, 2008 market value of TW Common would result in a net loss of approximately $4$5 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,~~September 30, 2008 to provide assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and such

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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,~~September 30, 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~~

Other than with respect to the risk factors set forth below, 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~~CenterPoint Houston must seek recovery of significant restoration costs arising from Hurricane Ike.

~~Conversion~~

CenterPoint Houston’s electric delivery system suffered substantial damage as a result of ~~3.75% Convertible Senior Notes due 2023.~~~~Since February 20,~~Hurricane Ike, which struck the upper Texas coast on September 13, 2008. The total cost for the restoration of the system is currently estimated to be in the range of $650 million to $750 million, but that estimate is preliminary and costs ultimately incurred could vary from that estimate.

CenterPoint Houston believes it is entitled to recover prudently incurred storm costs in accordance with applicable regulatory and legal principles. CenterPoint Houston plans to seek passage of legislation to allow securitization of the storm restoration costs through the issuance of dedicated bonds, which would be repaid over time through a charge imposed on customers. Alternatively, CenterPoint Houston has the right to seek recovery of these costs under traditional rate making principles. CenterPoint Houston’s failure to recover costs incurred as a result of Hurricane Ike could adversely affect its liquidity and financial condition.

CenterPoint Houston’s receivables are concentrated in a small number of retail electric providers, and any delay or default in payment could adversely affect CenterPoint Houston’s cash flows, financial condition and results of operations.

CenterPoint Houston’s receivables from the distribution of electricity are collected from retail electric providers that supply the electricity CenterPoint Houston distributes to their customers. As of September 30, 2008, weCenterPoint Houston did business with 80 retail electric providers. Adverse economic conditions, structural problems in the market served by the Electric Reliability Council of Texas, Inc. or financial difficulties of one or more retail electric providers could impair the ability of these retail providers to pay for CenterPoint Houston’s services or could cause them to delay such payments. CenterPoint Houston depends on these retail electric providers to remit payments on a timely basis. Applicable regulatory provisions require that customers be shifted to a provider of last resort if a retail electric provider cannot make timely payments. Applicable Texas Utility Commission regulations limit the extent to which CenterPoint Houston can demand credit protection from retail electric providers for payments not made prior to the shift to the provider of last resort. RRI, through its subsidiaries, is CenterPoint Houston’s largest customer. Approximately 48% of CenterPoint Houston’s $182 million in billed receivables from retail electric providers at September 30, 2008 was owed by subsidiaries of RRI. Any delay or default in payment could adversely affect CenterPoint Houston’s cash flows, financial condition and results of operations. RRI’s unsecured debt ratings are currently below investment grade. If RRI were unable to meet its obligations, it could consider, among various options, restructuring under the bankruptcy laws, in which event RRI’s subsidiaries might seek to avoid honoring their obligations and claims might be made by creditors involving payments CenterPoint Houston has received from RRI’s subsidiaries.

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

We currently have ~~issued 533,737 shares~~general liability and property insurance in place to cover certain of our ~~common stock upon conversion~~facilities in amounts that we consider appropriate. Such policies are subject to certain limits and deductibles and do not include business interruption coverage. Insurance coverage may not be available in the future at current costs or on commercially reasonable terms, and the insurance proceeds received for any loss of, ~~approximately $21.4 million aggregate principal amount~~or any damage to, any of our ~~3.75% Convertible Senior Notes due 2023,~~facilities maynot be sufficient to restore the loss or damage without negative impact on our results of operations, financial condition and cash flows.

In common with other companies in its line of business that serve coastal regions, CenterPoint Houston does not have insurance covering its transmission and distribution system because CenterPoint Houston believes it to be cost prohibitive. CenterPoint Houston may not be able to recover the losses and damages to its transmission and distribution properties as ~~set forth~~a result of Hurricane Ike, or any such losses or damages sustained in the ~~table below:~~future, through a change in its regulated rates, and any such recovery may not be timely granted. Therefore, CenterPoint Houston may not be able to restore loss of, or damage to, any of its transmission and distribution properties without negative impact on its results of operations, financial condition and cash flows.

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


~~(1)~~		~~Based on terms of the notes, settled entirely through the issuance of shares except for a payment of cash in lieu of fractional shares.~~

~~(2)~~		The number of shares issued in respect of any principal amount of notes converted is in addition to payment of cash in an amount equal to the principal amount of such notes and cash in lieu of fractional shares.

The ~~shares~~continued credit crisis and related turmoil in the global financial system may have an impact on our business and our financial condition. Our ability to access the capital markets may be severely restricted at a time when we would like, or need, to access those markets, which could have an impact on our flexibility to react to changing economic and business conditions. In addition, the cost of debt financing and the proceeds of equity financing may be materially adversely impacted by these market conditions. With respect to our existing debt arrangements, Lehman Brothers Bank, FSB, which had an approximately four percent participation in our credit facility and each of the credit facilities of our ~~common stock were issued solely to former holders~~subsidiaries, stopped funding its commitments following the bankruptcy filing of ~~our 3.75% Convertible Senior Notes due 2023 upon conversion pursuant~~its parent in September 2008, effectively causing a minor reduction to the ~~exemption from registration provided~~total available capacity under ~~Section 3(a)(9) of~~ the ~~Securities Act of 1933, as amended. This exemption is available because~~three facilities. The credit crisis could have an impact on our remaining lenders or our customers, causing them to fail to meet their obligations to us. Additionally, the ~~shares of~~crisis could have a broader impact on business in general in ways that could lead to reduced electricity and gas usage, which could have a negative impact on 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~~revenues.

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.

Item 5. 5. OTHER INFORMATION

The ratio of earnings to fixed charges for the ~~three~~nine months ended ~~March 31,~~September 30, 2007 and 2008 was ~~2.16~~1.87 and ~~2.25,~~2.21, respectively. We do not believe that the ratios for these ~~three-month~~nine-month periods are necessarily indicators of the ratios for the twelve-month periods due to the seasonal nature of our business. The ratios were calculated pursuant to applicable rules of the Securities and Exchange Commission.

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Item 6. EXHIBITS

~~The following exhibits are filed herewith:~~

The following exhibits are filed herewith:

Exhibits not incorporated by reference to a prior filing are designated by a cross (+); all exhibits not so designated are incorporated by reference to a prior filing of CenterPoint Energy, Inc.

SEC File
or
Exhibit Registration Exhibit
Number Description Report or Registration Statement Number Reference
3.1.1 — Amended and Restated Articles of Incorporation of CenterPoint Energy CenterPoint Energy’s Registration Statement on Form S-4 3-69502 3.1

3.1.2 — Articles of Amendment to Amended and Restated Articles of Incorporation of CenterPoint Energy dated March 27, 2002 CenterPoint Energy’s Form 10-K for the year ended December 31, 2001 1-31447 3.1.1

+3.1.3 — Articles of Amendment to Amended and Restated Articles of Incorporation of CenterPoint Energy dated April 24, 2008

3.2 — Amended and Restated Bylaws of CenterPoint Energy CenterPoint Energy’s Form 8-K dated January 24, 2008 1-31447 3.1

3.3 — Statement of Resolution Establishing Series of Shares designated Series A Preferred Stock of CenterPoint Energy CenterPoint Energy’s Form 10-K for the year ended December 31, 2001 1-31447 3.3

4.1 — Form of CenterPoint Energy Stock Certificate CenterPoint Energy’s Registration Statement on Form S-4 3-69502 4.1

4.2 — Rights Agreement dated January 1, 2002, between CenterPoint Energy and JPMorgan Chase Bank, as Rights Agent CenterPoint Energy’s Form 10-K for the year ended December 31, 2001 1-31447 4.2

4.3 — $1,200,000,000 Second Amended and Restated Credit Agreement, dated as of June 29, 2007, among CenterPoint Energy, as Borrower, and the banks named therein CenterPoint Energy’s Form 10-Q for the quarter ended June 30, 2007 1-31447 4.3

4.4 — $300,000,000 Second Amended and Restated Credit Agreement, dated as of June 29, 2007, among CenterPoint Houston, as Borrower, and the banks named therein CenterPoint Energy’s Form 10-Q for the quarter ended June 30, 2007 1-31447 4.4

4.5 — $950,000,000 Second Amended and Restated Credit Agreement, dated as of June 29, 2007 among CERC Corp., as Borrower, and the banks named therein CenterPoint Energy’s Form 10-Q for the quarter ended June 30, 2007 1-31447 4.5

SEC File
or
Exhibit Registration Exhibit
Number Description Report or Registration Statement Number Reference
10.1 — Form of Performance Share Award Agreement for 20XX — 20XX Performance Cycle under the Long-Term Incentive Plan of CenterPoint Energy, Inc. CenterPoint Energy’s Form 8-K dated February 20, 2008 1-31447 10.1

10.2 — Form of Stock Award Agreement (With Performance Goal) under the Long-Term Incentive Plan of CenterPoint Energy, Inc. CenterPoint Energy’s Form 8-K dated February 20, 2008 1-31447 10.2

10.3 — First Amendment to CenterPoint Energy, Inc. Deferred Compensation Plan (as amended and restated effective January 1, 2003) CenterPoint Energy’s Form 8-K dated February 20, 2008 1-31447 10.3

10.4 — CenterPoint Energy 2005 Deferred Compensation Plan (effective January 1, 2008) CenterPoint Energy’s Form 8-K dated February 20, 2008 1-31447 10.3

+12 — Computation of Ratios of Earnings to Fixed Charges

+31.1 — Rule 13a-14(a)/15d-14(a) Certification of David M. McClanahan

+31.2 — Rule 13a-14(a)/15d-14(a) Certification of Gary L. Whitlock

+32.1 — Section 1350 Certification of David M. McClanahan

+32.2 — Section 1350 Certification of Gary L. Whitlock

+99.1 — Items incorporated by reference from the CenterPoint Energy Form 10-K. Item 1A “Risk Factors”

Exhibit Number		Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference
3.1.1	—	Restated Articles of Incorporation of CenterPoint Energy	CenterPoint Energy’s Form 8-K dated July 24, 2008	1-31447	3.1
3.2	—	Amended and Restated Bylaws of CenterPoint Energy	CenterPoint Energy’s Form 8-K dated July 24, 2008	1-31447	3.2
4.1	—	Form of CenterPoint Energy Stock Certificate	CenterPoint Energy’s Registration Statement on Form S-4	3-69502	4.1
4.2	—	Rights Agreement dated January 1, 2002, between CenterPoint Energy and JPMorgan Chase Bank, as Rights Agent	CenterPoint Energy’s Form 10-K for the year ended December 31, 2001	1-31447	4.2
4.3	—	$1,200,000,000 Second Amended and Restated Credit Agreement dated as of June 29, 2007, among CenterPoint Energy, as Borrower, and the banks named therein	CenterPoint Energy’s Form 10-Q for the quarter ended June 30, 2007	1-31447	4.3
+4.4	—	First Amendment to Amended and Restated Credit Agreement dated as of August 20, 2008, among CenterPoint Energy, as Borrower, and the banks named therein.
4.5	—	$300,000,000 Second Amended and Restated Credit Agreement dated as of June 29, 2007, among CenterPoint Houston, as Borrower, and the banks named therein	CenterPoint Energy’s Form 10-Q for the quarter ended June 30, 2007	1-31447	4.4
4.6	—	$950,000,000 Second Amended and Restated Credit Agreement dated as of June 29, 2007, among CERC Corp., as Borrower, and the banks named therein	CenterPoint Energy’s Form 10-Q for the quarter ended June 30, 2007	1-31447	4.5
+10.1	—	Amended and Restated CenterPoint Energy 2005 Deferred Compensation Plan effective as of January 1, 2009
+10.2	—	Amended and Restated Houston Light & Power Company Executive Incentive Compensation Plan effective as of January 1, 1985
+10.3	—	First Amendment dated October 17, 2008 to Amended and Restated Houston Light & Power Company Executive Incentive Compensation Plan effective as of January 1, 1985
+12	—	Computation of Ratios of Earnings to Fixed Charges

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Exhibit Number		Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference
+31.1	—	Rule 13a-14(a)/15d-14(a) Certification of David M. McClanahan
+31.2	—	Rule 13a-14(a)/15d-14(a) Certification of Gary L. Whitlock
+32.1	—	Section 1350 Certification of David M. McClanahan
+32.2	—	Section 1350 Certification of Gary L. Whitlock
+99.1	—	Items incorporated by reference from the CenterPoint Energy Form 10-K. Item 1A “Risk Factors”

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SIGNATURES

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

	CENTERPOINT ENERGY, INC.


	By: /s/ Walter L. Fitzgerald
	Walter L. Fitzgerald
	Senior Vice President and Chief Accounting Officer

Date: November 5, 2008

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Index to Exhibits

The following exhibits are filed herewith:

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

Exhibit Number		Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference
3.1.1	—	Restated Articles of Incorporation of CenterPoint Energy	CenterPoint Energy’s Form 8-K dated July 24, 2008	1-31447	3.1
3.2	—	Amended and Restated Bylaws of CenterPoint Energy	CenterPoint Energy’s Form 8-K dated July 24, 2008	1-31447	3.2
4.1	—	Form of CenterPoint Energy Stock Certificate	CenterPoint Energy’s Registration Statement on Form S-4	3-69502	4.1
4.2	—	Rights Agreement dated January 1, 2002, between CenterPoint Energy and JPMorgan Chase Bank, as Rights Agent	CenterPoint Energy’s Form 10-K for the year ended December 31, 2001	1-31447	4.2
4.3	—	$1,200,000,000 Second Amended and Restated Credit Agreement dated as of June 29, 2007, among CenterPoint Energy, as Borrower, and the banks named therein	CenterPoint Energy’s Form 10-Q for the quarter ended June 30, 2007	1-31447	4.3
+4.4	—	First Amendment to Amended and Restated Credit Agreement dated as of August 20, 2008, among CenterPoint Energy, as Borrower, and the banks named therein.
4.5	—	$300,000,000 Second Amended and Restated Credit Agreement dated as of June 29, 2007, among CenterPoint Houston, as Borrower, and the banks named therein	CenterPoint Energy’s Form 10-Q for the quarter ended June 30, 2007	1-31447	4.4
4.6	—	$950,000,000 Second Amended and Restated Credit Agreement dated as of June 29, 2007, among CERC Corp., as Borrower, and the banks named therein	CenterPoint Energy’s Form 10-Q for the quarter ended June 30, 2007	1-31447	4.5
+10.1	—	Amended and Restated CenterPoint Energy 2005 Deferred Compensation Plan effective as of January 1, 2009
+10.2	—	Amended and Restated Houston Light & Power Company Executive Incentive Compensation Plan effective as of January 1, 1985
+10.3	—	First Amendment dated October 17, 2008 to Amended and Restated Houston Light & Power Company Executive Incentive Compensation Plan effective as of January 1, 1985
+12	—	Computation of Ratios of Earnings to Fixed Charges

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Exhibit Number		Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference
+31.1	—	Rule 13a-14(a)/15d-14(a) Certification of David M. McClanahan
+31.2	—	Rule 13a-14(a)/15d-14(a) Certification of Gary L. Whitlock	~~CENTERPOINT ENERGY, INC.~~
+32.1	~~By:~~ —	~~/s/ Walter L. Fitzgerald~~ Section 1350 Certification of David M. McClanahan
+32.2	—	Section 1350 Certification of Gary L. Whitlock	~~Walter L. Fitzgerald~~
+99.1	—	Items incorporated by reference from the CenterPoint Energy Form 10-K. Item 1A “Risk Factors”	~~Senior Vice President and Chief Accounting Officer~~

~~Date: April 30, 2008~~

~~EXHIBIT INDEX~~

Texas		74-0694415
~~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)


Large accelerated filerþ	Accelerated filero	Non-accelerated filero	Smaller reporting companyo
		(Do not check if a smaller reporting company)

PART I.	FINANCIAL INFORMATION

Item 1.	Financial Statements	1

	~~PART I. FINANCIAL INFORMATION~~Condensed Statements of Consolidated Income
	Three and Nine Months Ended September 30, 2007 and 2008 (unaudited)	1

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

	Condensed Statements of Consolidated Cash Flows
	Nine Months Ended September 30, 2007 and 2008 (unaudited)	4

	Notes to Unaudited Condensed Consolidated Financial Statements	5

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	25

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	38

Item 4.	Controls and Procedures	39

PART II.	OTHER INFORMATION

Item 1. ~~Financial Statements~~	Legal Proceedings		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~~		3640

Item 1A.	~~PART II. OTHER INFORMATION~~Risk Factors	40

Item ~~1. Legal Proceedings~~5.	Other Information	41
		36
Item ~~1A. Risk Factors~~6.	Exhibits		3642
~~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~~


	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


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


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

	•	·	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 or re-regulation of our businesses, 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 rates 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;


	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

	•	·	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;

	•	·	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 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


	Three Months Ended						Three Months Ended September 30,						Nine Months Ended September 30,
	March 31,						2007			2008			2007			2008
	2007			2008
Revenues	$	3,106		$	3,363		$	1,882		$	2,515		$	7,021		$	8,548


Expenses:
Natural gas		2,150			2,393			991			1,532			4,349			5,675
Operation and maintenance		352			365			349			371			1,031			1,078
Depreciation and amortization		145			158			170			194			475			540
Taxes other than income taxes		106			111			85			81			284			285

Total		2,753			3,027			1,595			2,178			6,139			7,578

Operating Income		353			336			287			337			882			970


Other Income (Expense):
Loss on Time Warner investment		(44	)		(54	)		(58	)		(36	)		(74	)		(73	)
Gain on indexed debt securities		41			50			56			33			70			66
Interest and other finance charges		(123	)		(115	)		(126	)		(116	)		(368	)		(344	)
Interest on transition bonds		(31	)		(33	)		(30	)		(34	)		(93	)		(102	)
Distribution from AOL-Time Warner litigation settlement								32			—			32			—
Additional distribution to ZENS holders								(27	)		—			(27	)		—
Other, net		6			13			11			29			23			56

Total		(151	)		(139	)		(142	)		(124	)		(437	)		(397	)


Income Before Income Taxes		202			197			145			213			445			573
Income tax expense		(72	)		(74	)		(54	)		(77	)		(154	)		(213	)

Net Income	$	130		$	123		$	91		$	136		$	291		$	360


Basic Earnings Per Share	$	0.41		$	0.38		$	0.29		$	0.40		$	0.91		$	1.08


Diluted Earnings Per Share	$	0.38		$	0.36		$	0.27		$	0.39		$	0.85		$	1.05

	December 31, 2007		September 30, 2008
Current Assets:
Cash and cash equivalents	$	129	$	84
Investment in Time Warner common stock		357		284
Accounts receivable, net		910		784
Accrued unbilled revenues		558		243
Natural gas inventory		395		598
Materials and supplies		95		120
Non-trading derivative assets		38		75
Taxes receivable		—		289
Prepaid expenses and other current assets		306		360
Total current assets		2,788		2,837

Property, Plant and Equipment:
Property, plant and equipment		13,250		13,766
Less accumulated depreciation and amortization		3,510		3,617
Property, plant and equipment, net		9,740		10,149

Other Assets:
Goodwill		1,696		1,696
Regulatory assets		2,993		3,219
Non-trading derivative assets		11		9
Notes receivable from unconsolidated affiliates		148		323
Other		496		799
Total other assets		5,344		6,046

Total Assets	$	17,872	$	19,032

	•	·	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

	Quoted Prices in Active Markets for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Netting Adjustments (1)			Balance as of September 30, 2008
	(in millions)
Assets
Corporate equities		$	286	$	—	$	—	$	—			$	286
Investments			67		—		—		—				67
Derivative assets			24		111		38		(89	)			84
Total assets		$	377	$	111	$	38	$	(89	)		$	437
Liabilities
Indexed debt securities derivative		$	—	$	195	$	—	$	—			$	195
Derivative liabilities			31		124		97		(183	)			69
Total liabilities		$	31	$	319	$	97	$	(183	)		$	264


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


	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

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

	Three Months Ended September 30,
	2007						2008
	Pension Benefits			Postretirement Benefits			Pension Benefits			Postretirement Benefits
	(in millions)
Service cost	$	9		$	—		$	8		$	—
Interest cost		25			7			25			6
Expected return on plan assets		(38	)		(2	)		(37	)		(3	)
Amortization of prior service cost		(1	)		—			(2	)		—
Amortization of net loss		8			—			6			—
Amortization of transition obligation		—			2			—			2
Net periodic cost	$	3		$	7		$	—		$	5

	•	·	reversed the Texas Utility Commission’s ruling that had denied recovery of a portion of the capacity auction true-up amounts;

	•	·	reversed the district court’s judgment to the extent it restored the capacity auction true-up amounts;

	•	·	ordered that the tax normalization issue described below be remanded to the Texas Utility Commission as requested by the Texas Utility Commission; and


	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


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


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